BILL ANALYSIS 1
1
SENATE ENERGY, UTILITIES AND COMMUNICATIONS COMMITTEE
DEBRA BOWEN, CHAIRWOMAN
SB 47X - Battin Hearing Date:
March 6, 2001 S
As Introduced: February 22, 2001 FISCAL B
X
1
4
7
DESCRIPTION
Current law describes a process for determining the price paid
by utilities, and their ratepayers, for electricity produced by
certain non-utility electricity generators, known as Qualifying
Facilities (QFs). That process contains two methodologies for
determining the price - one of which relies on prices paid by
the Power Exchange (PX) and one of which relies on natural gas
prices at the California border. QFs have the one-time choice
of switching from the California border methodology to the PX
methodology.
This bill specifies the price and/or the formulas for
determining the price for electricity generated by QFs which
shall be in effect for five years, as detailed below:
q Existing factors regarding seasonality and time of use are
frozen for five years.
q (391.4(a)) Renewable QFs will get paid 5.37 cents per
kilowatthour (kwh) for energy (plus capacity payments).
q (391.4(b)(1)) Some renewable QFs will have the option to
terminate their existing fixed price contracts early and
instead get 5.37 cents/kwh. If they choose not to terminate
those contracts early, then the QF gets to choose between the
avoided cost as determined by the California Public Utilities
Commission (CPUC) or 5.37 cents/kwh adjusted based on changes
in gas prices.
q (391.4(b)(2)) Some renewable QFs will have their choice of a
combination of the above option and a second option.
q (391.4(c)) Some renewable QFs whose contracts expire this
year will receive 5.37 cents/kwh.
q (391.4(d)) A wind-powered QF with a contract with Southern
California Edison (SCE) that has chosen a specified payment
option shall have their contract amended to change that
payment option and shall be paid 7.8 cents/kwh. No adjustment
for seasonality or time of delivery is permitted. It is the
intent of the Legislature that SCE and parties with this
option waive all pending claims and disputes.
q Payments to solar-thermal QFs shall be based 75% on 5.37
cents/kwh and 25% on the methodology used to determine
payments to gas-fired QFs. The CPUC is barred from
challenging attempts by these QFs to amend their Federal
Energy Regulatory Commission (FERC) certification orders.
q Renewable QFs which have exercised their authority to switch
between the two statutorily-prescribed cost calculation
methodologies will receive 5.02 cents/kwh for a term that
varies by the date upon which the QF switched. Gas-fired QFs
that have switched will receive the price determined for
gas-fired QFs that have not switched, discounted by 0.35
cents/kwh for a term which varies by the date upon which the
QF switched. All switching QFs shall be paid the PX price for
energy delivered between the QF switch date and December 31,
2000.
q Upon appropriation, $20 million is transferred as a subsidy to
biomass-fueled QFs. The intent is to provide $20 million per
year for five years ($100 million total) to pay for this
program.
q (391.7(d)) A biomass QF whose forecast energy payments
terminate between February 1, 2001 and June 30, 2006 shall be
paid 5.37 cents/kwh through June 30, 2006.
q Prices paid to gas-fired QFs are linked to long-term prices of
natural gas, though the QF is not obligated to purchase
long-term natural gas. Several options are articulated.
This bill establishes a schedule for payment of past-due amounts
with payments no later than April 2, 2001 for November 2000
electric deliveries, May 1, 2001 for December 2000 electric
deliveries, and June 1, 2001 for January electric deliveries.
This bill requires the CPUC to approve the contract
modifications described above without alteration or amendment.
This bill provides a gas-fired QF with several options relative
to obtaining a long-term gas contract and requires the State
Treasurer or his designee to approve those contracts.
This bill sunsets on July 1, 2006.
This bill is an urgency statute.
BACKGROUND
What Is A QF?
In 1978 Congress and the President enacted the Public Utility
Regulatory Policies Act (PURPA) which encouraged competition in
the power generation market through the creation of non-utility
power producers known as qualifying facilities (QFs).
To accomplish this, PURPA required the utilities to purchase
power from the QFs and to pay those QFs the utilities' "avoided
cost" - the cost that the utility would otherwise pay to
generate or procure power. The cost of QF power is then passed
through to utility customers.
PURPA, with its mandate to encourage cogeneration and small
power production, created two kinds of QFs. The largest are the
cogeneration QFs, which recycle the waste heat from electric
generation into a production process (i.e. to heat something
else). These are described as gas-fired QFs in the bill because
they use natural gas as their fuel. The second type of QF is an
electric generator which relies on renewable energy sources for
fuel, such as wind, biomass combustion, or geothermal steam.
These are collectively known in the bill as non-gas fired QFs.
PURPA requires the electric utility to purchase the electricity
from the QFs at rates which "shall be just and reasonable to the
electric customers of the electric utility and in the public
interest". Further, that rate may not exceed the utility's
avoided cost.
"Avoided cost" is determined by the CPUC. That cost was
computed based upon a formula which estimated the cost of
running an additional gas-fired powerplant. When California's
electric market was restructured in 1996, the method, but not
the formula, for determining avoided cost was dealt with in the
statutes. AB 1890 (Brulte), Chapter 854, Statutes of 1996,
established an avoided cost methodology based on competitive
prices as established through the PX. AB 1890 also created an
alternative methodology for avoided cost which relies on natural
gas prices at the California border. That interim methodology
established parameters which the CPUC has implemented and is
currently reconsidering (see below).
The avoided cost standard is much different than the actual cost
of operating the powerplant. The standard is based on a
hypothetical gas-fired powerplant where gas is purchased on the
spot market. Yet, as noted above, many QFs run on fuel other
than natural gas. Also, many QFs don't buy natural gas on the
spot market, they rely on long-term contracts to keep their
underlying costs stable. Furthermore, using the avoided cost
methodology doesn't account for the benefits of the recycling of
the waste heat (i.e. the cogeneration).
Some consumer groups and utilities have argued for years that
the prices for QF-produced electricity is too costly and that
argument continues today.
CPUC Proposed Decision
Pursuant to a July 2000 request by SCE, the CPUC is currently
examining whether its existing methodology for determining the
prices paid to QFs is reasonable.
Historically, SCE has paid its QFs about 3.1 cents/kwh for their
energy output, in addition to capacity payments (payments made
for the availability of the capacity to produce energy) of
around 2 cents/kwh. In June 2000, those QF prices started to
rise markedly from the historic average of 3.1 cents to over 5
cents, reflecting changes to the inputs of the avoided cost
formulas the CPUC had adopted pursuant to AB 1890 (however, the
capacity payments stayed the same). In January 2001, QF prices
exceeded 17 cents, nearly matching the increase in cost for
electricity purchased on the wholesale market.
On January 9, 2001 the CPUC issued a proposed decision by
Commissioner Carl Wood to modify the existing methodology for
SCE and cap the overall price to all QFs at 6.745 cents/kwh,
consistent with the FERC's benchmark for just and reasonable
rates for short term energy purchases.
The proposed Wood decision has been controversial, with some
arguing the 6.745 cent/kwh cap is below the cost of production
for some QFs and if implemented, would force many QFs to
discontinue operation.
Long List of Creditors
As with other utility creditors, the QFs have not been paid for
electricity they have already delivered. SCE has not paid the
QFs for power sold since November 2000, while PG&E has made only
partial payments for power sold since December 2000. This has
caused some QFs to discontinue operation as they are unable to
pay their suppliers (natural gas suppliers, chief among them)
and cover their debts. PG&E indicates it currently has 500
megawatts of mostly gas-fired QF capacity shut down with an
additional 400 MW indicating an intention to shut down or reduce
deliveries.
QF Profile by Utility
QF capacity as
a percentage of need Contract capacity
Number of contracts
PG&E 22% 3000 MW 400
SCE 28% 5000 MW 300
SDG&E <10% 300 MW 5
QUESTIONS
1.Is it appropriate to effectively re-write over 600 individual
contracts in statute, as this bill attempts to do?
2.Is it appropriate to effectively turn the Legislature into the
CPUC for the purposes of setting QF payment rates,
establishing specific contract terms, and requiring the CPUC
to approve the modifications set forth in this bill?
3.Is it appropriate to lock certain payment rates and formulas
into statute for five years?
4.What is the effect of this bill on electric rates?
5.What are the risks of not passing this bill? How will this
effect reliability? Are there alternative ways to accomplish
the goals of the bill?
6.Is it appropriate to provide $20 million in taxpayer funds to
certain biomass producers in an effort to keep electricity
rates low for those who purchase power from these facilities?
7.Is it appropriate to assign the State Treasurer or his
designee the responsibility for deciding what is or isn't an
appropriate long-term natural gas contract?
8.Is it appropriate to make the QFs into a priority creditor, as
this bill appears to do?
9.Will this bill result in the QFs being paid by the utilities,
either on a going forward basis or for the back debt owed to
them by the utilities?
COMMENTS
Overview. This bill is the result of ongoing negotiations
between the QF industry, utilities, and the authors. The overall
intent of the bill is to provide stability for the prices paid
to QFs by pegging those prices to the price of five-year gas
contracts and enshrining those prices for five years. The bill
codifies many of the specific provisions of those negotiations
and as a result has special provisions negotiated for specific
types of QFs. To effect its intent, the bill envisions a number
of "side agreements" which are neither codified nor subject to
third-party review. The bill strives to provide certainty to
the parties by precluding any revision of the contracts by the
CPUC.
There is a tension between the use of avoided cost as prescribed
by PURPA and the goal of keeping electric rates low and stable.
That's because the avoided cost methodology as defined in
existing law is based on the spot price of natural gas. As
evidenced by recent experience, spot prices are very volatile
and high in times of shortage. This bill uses five-year year
gas prices as a means of stabilizing prices, but at the risk of
imposing higher costs in the future and no assurance that any QF
will be able to sign a five-year natural gas contract.
Private Contracts, The Legislature, & The CPUC. The more than
600 QFs in the state are under contract to deliver electricity
to the state's investor-owned and municipal utilities. Some of
these contracts have specified terms and are not subject to CPUC
approval. Most of these contracts have some terms which are
specified and others terms which are determined by the CPUC.
This bill deals with both types of contracts.
Current law specifies the methodologies for determining the
price of QF electricity which rely in part on a non-operative PX
and are specifically tied to natural gas prices at the
California border. Clearly, the statutes must be revised to
replace the reliance on the PX price. However, instead of
allowing the CPUC to determine a new avoided cost that relies on
something other than the California border price of natural gas,
this bill seeks to lower current avoided costs by codifying
specific pricing and formulas for five years. After that
five-year period elapses, the bill returns to a reliance on the
non-existent PX as a price index. This method virtually ensures
that utility customers will overpay for energy over the medium
term (based on current forecasts of gas costs), though it does
have the benefit of ensuring stable QF prices.
Successful implementation of AB 1X (Keeley), Chapter 4, Statutes
of 2001 relies on lowering QF costs, which will free up money
against which the Department of Water Resources (DWR) can issue
bonds to lower and stabilize electricity costs. Until QF costs
are lowered, it will be difficult to issue bonds, mean money
will have to continue to be provided by the General Fund in
order to buy the power necessary to keep the lights on in
California.
How Will Customer Bills Be Affected? Pacific Gas & Electric
(PG&E) indicates that under the provisions of this bill, its
payments to renewable QFs will be around 7.8 cents/kwh while
payments to its gas-fired QFs will be 8-8.5 cents/kwh based on
current gas prices. SCE indicates its renewable QF payments
will be around 8.5-8.6 cents/kwh in 2001, dropping to 8.1
cents/kwh in 2005, while payments to its gas-fired QFs will be
8.3-8.4 cents/kwh.
Translating the effect of these prices on customer bills can't
be done without also knowing the cost of the portfolio of long
term contracts being acquired by the DWR pursuant to AB 1X. As
the price of QF power rises, the amount of revenue available to
pay for the DWR power shrinks, which puts pressure on the CPUC
to increase electricity rates to cover those costs.
At the time AB 1X was moving through the Legislature, there was
a belief by some that if the cost of QF power dropped to 7.8
cents/kwh, that would leave enough revenue to pay for DWR's
power costs and to make a contribution to the undercollections
of PG&E and SCE without raising rates. However, as noted above,
because no one knows what DWR is paying for power, it's
impossible to determine whether the belief described above will
translate into reality.
What's The Effect of Buying A Majority of California's Long Term
Power Needs Now? Under AB 1X, DWR is authorized to substitute
for electric utilities in purchasing electricity which the
utilities can't otherwise provide. That purchasing, which may
account for one-third of electricity used by investor-owned
utility (IOU) customers, relies on long-term contracts as a
means of lowering costs. Because those contracts are all being
negotiated at the same time and at the height of the market, it
means the cost of each contract will be higher and/or longer
than they would be if the contracts were being negotiated during
a time of over supply and low spot market energy prices.
Ideally, such contracts would be procured over months, if not
years, so the market could absorb the demand without unduly
affecting price.
This bill contemplates setting prices for another 20%-30% of
electricity used in the state (i.e. that electricity produced by
the QFs) at the same time as those long-term electric contracts
are being negotiated. The common factor to both the long-term
electric contracts and the QF pricing is medium term natural
gas. Putting QF gas demand on the market simultaneously with
the gas demand resulting from the long-term electric contracts
is likely to raise the pressure on natural gas prices even more
and, consequently, raise the pressure on electricity prices.
Negotiating these deals at a time when energy costs are at an
all-time high will no doubt guarantee long-term stability, but
that guarantee is likely to come at a high price.
Current Law Must be Changed . Under AB 1890, QF prices may be
set based on PX prices. That law obviously needs to be revised
in light of the demise of the PX. Further, AB 1890 also
requires the CPUC to establish avoided cost based on prices for
natural gas at the California border, precluding the use of any
other methods. The author and committee may wish to examine
whether that law should be changed.
Paying the QFs. Under AB 1X, the wholesale generators are being
paid for their ongoing electric sales, but their bills for
electricity sold in 2000 remain unpaid. This stands in contrast
to the QFs, who are not being paid for either their ongoing or
prior sales, despite the fact that the IOUs are continuing to
collect money from customers and the existing frozen rates being
paid by ratepayers include a component for paying QF costs.
Payment to the QFs from those funds for ongoing electric sales
would seem to be equitable and consistent with the way other
generators of electricity are being treated today.
SECTION BY SECTION COMMENTS
Section 391.2
This is the intent language section of the bill.
Subsection (a) states that AB 1X required the state to purchase
all of the electricity needed by the IOUs to cover their net
short position. While some believe that was the intent of AB
1X, the language of the statute imposes no such requirement.
Rather, it allows DWR to purchase power on behalf of customers.
This issue has been the subject of litigation, with some power
generators suing to require DWR to purchase the entire net short
instead of continuing its practice of setting a price, only
purchasing power offered for sale at or below that price, and
leaving it to the Independent System Operator (ISO) to purchase
any power priced over that set amount. If it's the author's
intent to require DWR to purchase the entire net short position
for each IOU, the author and committee may which to consider
whether it's appropriate to make the necessary changes to the
statutes created by AB 1X instead of setting up a conflict
between the AB 1X statute and the intent language of this bill.
Subsection (e) deals with altering the short-run avoided cost
(SRAC) methodology for all gas-fired QFs. There is some dispute
among the parties as to whether this section - and this bill -
require all contracts to use the new SRAC methodology or whether
it only applies to those gas-fired QFs who voluntarily amend
their contracts.
Subsection (f) deals with the benefits of biomass-to-energy
programs. There is some dispute among the parties as to whether
this section - and the bill - will put pressure on ratepayers to
fund this program if the $20 million in General Fund money isn't
made available each year as envisioned by this bill.
Section 391.3
Subsection (c) freezes the time-of-delivery and seasonal energy
allocation factors in effect on January 1, 2001 in place for
five years. Currently, the CPUC has the discretion to alter
these factors based on changes in energy use, etc.
Subsection (d) freezes the line loss factors at 1.0 for five
years unless the parties to a power purchase agreement agree to
a different factor. This overrides a CPUC proposed decision
issued in January that set line loss factors on a
facility-by-facility basis. The line loss factor deals with how
much power is "lost" when a facility transmits it down the line
to the utility. Generally, the further away a facility is from
the load, the greater the line loss. This provision of the bill
ensures that every QF will be paid the same amount, regardless
of line loss, and amounts to those facilities located closest
to the load subsiding those facilities who have to transmit
their power the furthest difference.
Subsection (e) requires the CPUC to provide standard form
amendments to each contract to implement the provisions of this
bill and requires the CPUC to provide in those amendments a
provision for full cost recovery. That means should the changes
made by this bill force the utilities to increase the rates
charged to consumers, the IOU will be automatically allowed to
pass those costs onto consumers without having to go before the
CPUC to request approval for a rate hike.
Subsection (f) precludes a QF from switching to the PX method of
pricing for five years, yet it allows a QF to switch to such a
pricing mechanism after that time, even though there is no
longer a functioning PX. The author and committee may wish to
consider whether this issue should be deferred for five years,
as this bill does, or whether it should be decided as a part of
this bill.
Subsection (g) includes the "full cost recovery" language noted
above. Furthermore, this subsection requires the CPUC to
approve all agreements between IOUs and QFs as a result of this
bill and precludes the CPUC from amending the agreements or
changing its decision at any point in the future. Subsection
(g)(2) further requires the CPUC to make an irrevocable
determination of per se reasonableness of the agreements,
including full cost recovery by the IOUs.
Subsection (h) specifies the payments to QFs from November 1,
2000 to February 1, 2001, barring the CPUC from revisiting that
issue.
Section 391.4
Subsection (a) sets the price paid for energy to most - but not
all - renewable QFs at 5.37 cents/kwh for five years. The
exceptions to this 5.37 cent price include some wind and solar
QFs that are dealt with elsewhere in the bill.
Subsection (b) deals with renewable QFs whose existing contracts
contain fixed energy provisions that will expire between now and
June 30, 2006. A renewable QF has a one-way option to (b)(1)(A)
terminate its existing contract and accept the payment terms
described above; (b)(1)(B)(i) wait until the fixed energy terms
of the contract expire and shift to SRAC payments and take the
SRAC methodology set by the CPUC; or (b)(1)(B)(ii) wait until
the fixed energy terms of the contract expire and shift to SRAC
payments that are based on a specific formula. That formula is
the product of 5.37 cents/kwh multiplied by the levelized cost
of a forward burntip (source) natural gas strip at the time of
conversion to June 30, 2006, divided by $6.50 per MMBtu. A
renewable QF that fails to make a selection within 30 days of
the effective date of this bill will be required to accept the
choice described in (b)(1)(B)(i).
This subsection appears to apply to 12 SCE contracts responsible
for generating 250 megawatts of electricity and one PG&E
contract that generates 15 megawatts of electricity.
Subsection (c) deals with specific renewable QFs whose contracts
expire this year, requiring these facilities to be paid 5.37
cents/kwh. This subsection reportedly applies to one facility
owned by San Diego Gas & Electric (SDG&E) and two facilities
owned by (PG&E).
Subsection (d) appears to deal with seven to eight SCE contracts
with renewable QFs that generate their power from wind.
Wind-powered QFs have the benefit of free fuel (wind) and the
detriment of an unreliable and unpredictable supply. Reliable
electricity is more valuable than intermittent electricity, and
electricity available during peak times is more valuable than
off-peak energy. Current QF pricing reflects that by adjusting
the price based on seasonality and time of production, but this
bill bars any such adjustment for five years. Capacity Option A
refers to "as available" contracts (the QF only delivers the
power when it has power), while Capacity Option B refers to
"firm" contracts (a specific amount of power is required to be
delivered at specific times). Most wind contracts are Capacity
Option A contracts since the wind isn't guaranteed to blow at
specific levels and/or at specific times. This bill converts
all "firm" contracts to "as available" contracts and sets the
price for the combined energy and capacity payment at 7.8
cents/kwh for five years (the 5.37 cents/kwh used for other
renewable QFs only covers the energy cost and doesn't speak to
the capacity payment). That payment amount is guaranteed
regardless of when the power is delivered (the 5.37 cents/kwh
paid to other renewables can vary based on allocation factors,
such as time of delivery, as long as the average is 5.37
cents/kwh), which is significant since the wind doesn't blow on
a predictable daily or yearly schedule. The author and
committee may wish to consider the wisdom of guaranteeing the
highest payments to these facilities.
Subsections (d)(2) and (d)(3) deal with how the wind QFs will be
paid after the five-year term of this bill expires. Pursuant to
(d)(2), the energy component of the 7.8 cents/kwh will be set by
the CPUC SRAC formula. However, pursuant to (d)(3), the
capacity payment will revert to a "firm" contract formula even
though the contract itself has been converted to an "as
available" contract.
Subsection (d)(4) states the intent of the Legislature that SCE
and wind-powered QFs covered by this bill waive any and all
claims against one another, as well as the intent that a QF
shall not be liable for any payments, refunds, or penalties to
SCE with respect to any pending claims.
Section 391.5
Subsection (a) deals with solar thermal powered renewable QFs.
These facilities are different from the more common
solar-electric technology in that solar thermal QFs use sunlight
to heat a liquid which then drives a turbine to generate
electricity. By contrast, solar-electric technology directly
converts sunlight to electricity. Solar thermal QFs also burn
natural gas to boost their efficiency. In a sense, these are
hybrid QFs and this subsection requires them to be paid on a
hybrid basis - 75% based on the formula for renewable QFs in the
bill and 25% based on the formula for gas-fired QFs. This is in
addition to the relatively high capacity payments these QFs
receive.
Subsection (b) precludes the CPUC from opposing a renewable QF
that has received FERC approval to rely on natural gas for 25%
of its energy. The CPUC has reportedly opposed such operations
under the belief that PURPA doesn't permit such operation. The
author and committee may wish to consider the appropriateness of
preventing the CPUC from intervening in a FERC proceeding.
There are approximately 9 of these facilities in California, all
in SCE's service territory, and they generate approximately 300
megawatts of electricity.
Section 391.6
This deals with QFs who switched avoided cost methodologies from
the California border natural gas price to the PX price and
appears to apply to about 40% of PG&E's QF contracts that
produce 1200 megawatts of electricity.
This bill switches those facilities back from the PX price to
the SRAC methodology used by the CPUC on January 1, 2001. The
QFs relying on the PX price to set the rate at which they were
paid have enjoyed tremendous profits since the PX prices rose
last year. The notion of this section is to compensate PG&E for
the higher costs it was forced to pay. The QFs covered by this
section will be paid at a lower rate on a going-forward basis
than the other QFs in this bill. The bill also specifies that
these switching QFs will enjoy the higher PX price through
December 31, 2000. PG&E and Calpine - who reportedly owns many
of the facilities that switched to PX pricing and are being
switched back by this bill - state the amount of the discount
provided to PG&E by this section is $115 million.
Section 391.7
AB 2872 (Shelley), Chapter 144, Statutes of 2000 and AB 2825
(Battin), Chapter 739, Statutes of 2000, together created the
Central Valley Agricultural Biomass-to-Energy Incentive Grant
Program. AB 2872 set aside $10 million a year for three years
to provide incentives for companies to convert their
agricultural waste into biomass fuel, instead of sending it to a
landfill or burning it in an open field. The statute also
prevented any facility accepting a subsidy from this program
from receiving any subsidy, rebate, buydown, or incentive from
the public goods surcharge program that collects $62.5 million
from electricity users to fund renewable energy grants each
year.
Subsections (a) and (b) are unique in this bill in that they
expand upon an existing grant program to subsidize
biomass-fueled QFs. These subsections create an expectation of
additional funding for the program through June 30, 2006.
Subsection (b), upon appropriation of $20 million in the budget,
provides money to biomass facilities to help compensate them for
the cost of fuel needed to operate their plants. The author and
committee may wish to consider whether it's appropriate to use
taxpayer dollars to help subsidize the cost of electricity
produced by biomass QFs in order to keep down the rates paid by
electricity users. There is no linkage between the taxpayer
subsidy and the cost of electricity. The author and committee
may wish to consider if in exchange for the taxpayer subsidy
there should be a requirement that the QF sell to the utilities
at cost-based rates.
Part of the rationale for this section of the bill is that using
agricultural waste to fuel electricity plants is much better for
air quality and the environment than burning the waste in an
open field, and thus provides a society-wide benefit. However,
there is no provision that prevents a biomass facility from
using the grant money it receives to pay to import waste fuel
from out of state. The author and committee may wish to
consider whether such a restriction is appropriate and should be
added to the bill.
Finally, the author and committee may wish to consider whether
the language added to last year's bill to preclude a facility
from "double-dipping" should be added to this bill as well.
Subsection (d) applies to the Colmac biomass facility in SCE's
service territory that produces an estimated 40 megawatts of
electricity. Under this provision, this facility will continue
to be paid at its contract rate (estimated at 15-16 cents/kwh)
until its contract expires in 2002, then will be paid 5.37
cents/kwh through June 2006.
Section 391.8
This section applies to gas-fired, not renewable, QFs.
Subsection (b) applies to PG&E gas-fired QFs, while subsection
(c) applies to SCE gas-fired QFs. The two utilities have always
used slightly different formulas and those formulas will
continue to be different under this bill. PG&E will continue to
use the existing statutorily created, CPUC-approved SRAC
formula, but the bill creates a new way to calculate the natural
gas cost factor that's plugged into the formula.
By contrast, the price for SCE's gas-fired QFs follows a formula
which is modeled on the cost of running an incremental gas-fired
turbine, similar to methodology that was in place before it was
changed pursuant to AB 1890. Under subsection (c), the SRAC
payment is calculated using a statutory-established heat rate, a
statutory-established operations & maintenance cost, and the
California Consumer Price Index. The author and committee may
wish to consider whether the Legislature, and not the CPUC, is
the appropriate body to set these figures and what impact this
will have on rates paid to QFs (and charged to ratepayers).
Subsection (d)(1) applies to four specific gas-fired QF
contracts with SCE. These QFs have contracts with specified
terms and conditions which are not subject to review by the
CPUC. This bill requires these contracts to be modified only in
accordance with the long-term gas price determinations pursuant
to subsection (g). If these contracts are not subject to review
by the CPUC, the author and committee may wish to consider how
it's possible for legislation to impose a change?
Subsection (d)(3) sets aside existing law (Public Utilities Code
Section 367(a)(2)) that precludes the cost associated with
extending any power purchase contract obligations (i.e. QF
contracts) from being collected from ratepayers through the
non-bypassable Competition Transition Charge. This bill
eliminates that requirement for four gas-fired QF contracts,
essentially finding that if those contracts are extended, they
will be, by definition, reasonable. The contracts in question
are reported to expire in 2005, 2007, and 2008 at times when
natural gas prices may be very different than they are today.
Subsection (e) applies to gas-fired QFs selling to SDG&E and use
the same provisions that are applied to the gas-fired QFs
selling to PG&E.
Subsection (g) sets up the process for establishing the
long-term gas prices used to determine the price paid to the
gas-fired QFs covered by this bill, but the bill doesn't require
the purchase of long-term gas contracts by QFs. This is a key
provision of the bill, as more than half of all California QFs
are gas-fueled.
QFs are required to choose one of three options for determining
a price for long-term natural gas contracts. Option 1 is a
Benchmark option which requires the IOUs and the State Treasurer
(or his/her designee) to select a procurement manager who will
select natural gas contracts. If a QF declines to take the
contract selected by the IOU and the State Treasurer, the QF
must accept the gas price used in the CPUC's current posted SRAC
price. The second option is the Portfolio option which
essentially tries to aggregate the needs of the QFs selecting
the option, requiring the IOU and the State Treasurer to
purchase a portfolio of long-term gas contracts for the QFs.
The third option is the Actual Cost option which leaves it to
the QF to purchase its own natural gas, subject to the approval
of the State Treasurer.
The IOUs and the state both have an interest in ensuring that
the long-term natural gas contracts entered into by the QFs are
as low as possible, which is why this bill requires the IOUs and
the State Treasurer (on behalf of the state) to approve all of
the contracts. The author and committee may wish to consider
whether it's appropriate to involve the State Treasurer in such
an arrangement and to exclude the CPUC, which has decades of
background in dealing with natural gas issues.
Section 391.9
This section sets up a payment schedule to require the IOUs to
become current on all payments owed to QFs by June 1, 2001.
Subsection (a)(2) requires SCE to be liable for the SRAC price
to all QFs on a going-forward basis should it not comply with
the payment schedule detailed in subsection (a).
Subsection (a)(3) waives all PG&E payments to QFs for November
2000. Should PG&E not comply with the payment schedule detailed
in subdivision (b), it too would be liable to the QFs for the
SRAC price for power on a going-forward basis.
This section appears to make the QFs into priority creditors of
the IOUs. The author and committee may wish to consider the
impact of such a provision and how it may affect other creditors
of the IOUs, which include DWR.
POSITIONS
Sponsor:
Author
Support:
-----------------------------------------------------------------
|Aldora Technology |Allwood Recycling |Altamont Power |
| | |Company, LLC |
|--------------------+--------------------+-----------------------|
|American Waste |Apollo Wood |Arch Coal, Inc. |
|Industries |Recovery, Inc. | |
|--------------------+--------------------+-----------------------|
|Atlas Tree Service, |AWI General |Berry Petroleum |
|Inc. |Engineering |Company |
|--------------------+--------------------+-----------------------|
|Blue Mountain |BMI Mechanical, |Boydston Construction, |
|Minerals |Inc. |Inc. |
|--------------------+--------------------+-----------------------|
|BSK Analytical |Burney Mountain |CA Biomass Energy |
|Laboratories |Power |Alliance |
|--------------------+--------------------+-----------------------|
|CA Chamber of |CA Cogeneration |CA Independent |
|Commerce |Council |Petroleum |
|--------------------+--------------------+-----------------------|
|CalWind Resources, |Cameron Ridge LLC |Canyon Fuel Company, |
|Inc. | |LLC |
|--------------------+--------------------+-----------------------|
|Center for Energy |Clean Power |Clem Systems |
|Efficiency |Campaign | |
| & Renewable | | |
|Technologies | | |
|--------------------+--------------------+-----------------------|
|Community Recycling |Coso Operating |Crockett Cogeneration |
|& |Company | |
| Resource | | |
|Recovery | | |
|--------------------+--------------------+-----------------------|
|Darrell L. Green |Delano Energy |Diamond of CA Board |
|Inc. | | |
|--------------------+--------------------+-----------------------|
|DMF Trucking |E.F. Oxnard, Inc. |Eastern Regional |
| | |Landfill |
|--------------------+--------------------+-----------------------|
|EcoChem Analytics |Environmental |ESI Bay Area GP, Inc. |
| |Defense | |
|--------------------+--------------------+-----------------------|
|ESI CC Limited |ESI HS Limited |ESI KF Limited |
|Partnership |Partnership |Partnership |
|--------------------+--------------------+-----------------------|
|ESI Mojave, LLC |Florin-Perkins |GEM Resources, LLC |
| |Landfill, Inc. | |
|--------------------+--------------------+-----------------------|
|Generating Resource |Green Ridge |GWF Power Systems |
| |Services | |
| Recovery | | |
|Partners, Oxnard | | |
|--------------------+--------------------+-----------------------|
|Harper Lake Company |Harris Industrial |Herber Geothermal |
|VIII |Gases |Company |
|--------------------+--------------------+-----------------------|
|HLC IX Company |Hurst Trading Inc. |Intravaia Rock & Sand, |
| | |Inc. |
|--------------------+--------------------+-----------------------|
|Jack Rabbit |Jay Dee Transport |Kori Enterprises |
| |Company | |
|--------------------+--------------------+-----------------------|
|Long Valley Fire |Mammoth-Pacific, LP |Mariani Nut Company |
|Protection | | |
|--------------------+--------------------+-----------------------|
|Mendota Biomass |MidAmerican Energy |Mojave 16/17/18 LLC |
|--------------------+--------------------+-----------------------|
|Mt. Lassen Power |National King Coal, |Ofc. of Ratepayer |
| |LLC |Advocates |
|--------------------+--------------------+-----------------------|
|Ogden Energy Group |Ogden Power |Ogden Power |
| |Pacific, Inc. |Pacific-Salinas |
| | | Power Plant |
|--------------------+--------------------+-----------------------|
|Ogden Power |Ogden Power |Ormesa Geothermal II |
|Pacific-Santa |Pacific- | |
| Clara Power | Stockton Power | |
|Plant |Plant | |
| | | |
|--------------------+--------------------+-----------------------|
|Pacific Coast |Pacific Energy |Pacific Energy |
|Chemicals Company |Operating |Operating Group, |
| | Group, | LP-Toyon Plant |
| |LP-Penrose Plant | |
|--------------------+--------------------+-----------------------|
|Pacific Inspection |Pacific Oroville |Pacific Ultra Power |
| |Power, Inc. |Chinese |
| | | |
| | |Station |
|--------------------+--------------------+-----------------------|
|Pacific Wood Fuels |Perez Farms |POSDEF Power Company |
|Co. | | |
|--------------------+--------------------+-----------------------|
|Procter & Gamble |Randazzo |Regional Council of |
| |Enterprises, Inc. |Rural |
| | | Counties |
|--------------------+--------------------+-----------------------|
|Constellation |Constellation |Constellation |
|Operating |Operating |Operating |
| Services-Rio | Services-Rio | Services-Rio Bravo |
|Bravo Jasmin |Bravo Poso |Rocklin |
|--------------------+--------------------+-----------------------|
|Safway Steel |San Joaquin |San Gorgonio Farms, |
|Products |Helicopters |Inc. |
|--------------------+--------------------+-----------------------|
|Scott Engineering |Second Imperial |Sky River Partnership |
| |Geothermal | |
|--------------------+--------------------+-----------------------|
|Smurfit-Stone |Southwest |Sunset Waste Paper |
|Container |Contractors | |
|--------------------+--------------------+-----------------------|
|Thermo ECOtek |TPC Windfarm LLC |Tracy Biomass Plant |
|--------------------+--------------------+-----------------------|
|U.S. Borax, Inc. |United Cogen, Inc. |UNIT Construction |
|--------------------+--------------------+-----------------------|
|Victory Garden |Volkl & Sons Inc. |Wheelabrator Hudson, |
|Phase IV | |Inc. |
|--------------------+--------------------+-----------------------|
|Wheelabrator |Wheelabrator |Wheelabrator Norwalk, |
|Lassen, Inc. |Martell, Inc. |Inc. |
|--------------------+--------------------+-----------------------|
|Wheelabrator |Willamette |Windpower Partners |
|Shasta, Inc. |Industries |1989 |
|--------------------+--------------------+-----------------------|
|Windpower Partners |Windpower Partners |Windpower Partners |
|1990 |1991 |1991-2 |
|--------------------+--------------------+-----------------------|
|Windpower Partners |Wood Recycling |Woodland Biomass |
|1992 |Center, Inc. |Power, Ltd. |
|--------------------+--------------------+-----------------------|
|5 Individuals | | |
-----------------------------------------------------------------
Oppose:
Edison International
The Utility Reform Network
Randy Chinn
SB 47X Analysis
Hearing Date: March 6, 2001