<PAGE>
REGISTRATION STATEMENT NO. 333-30715
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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
----------------------------
AMENDMENT NO. 1
TO
FORM S-3
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
----------------------------
CALIFORNIA INFRASTRUCTURE AND ECONOMIC DEVELOPMENT BANK
SPECIAL PURPOSE TRUST PG&E-1
(ISSUER OF SECURITIES)
PG&E FUNDING LLC
(Depositor of the Trust described herein)
(Exact Name of Registrant as Specified in Its Certificate of Formation)
DELAWARE 94-3274751
(State or Other Jurisdiction of (I.R.S. Employer
Organization) Identification Number)
PG&E FUNDING LLC
245 MARKET STREET, ROOM 424
SAN FRANCISCO, CA 94105
(415) 973-5467
(Address, Including Zip Code, and Telephone Number,
Including Area Code, of Registrant's Principal Executive Offices)
LESLIE EVERETT
CORPORATE SECRETARY
PG&E FUNDING LLC
245 MARKET STREET, ROOM 424
SAN FRANCISCO, CA 94105
(415) 973-5467
(Name, Address, Including Zip Code, and Telephone Number, Including Area Code,
of Agent For Service)
Copies to:
<TABLE>
<CAPTION>
<S> <C> <C>
DEAN E. CRIDDLE
MARK R. LEVIE ERIC D. TASHMAN GREGORY M. SHAW
ORRICK, HERRINGTON & SUTCLIFFE LLP CATHY M. KAPLAN CRAVATH, SWAINE & MOORE
Old Federal Reserve Bank Building BROWN & WOOD LLP Worldwide Plaza
400 Sansome Street 555 California Street, 50th Floor 825 Eighth Avenue
San Francisco, California 94111 San Francisco, California 94104 New York, New York 10019
</TABLE>
Approximate date of commencement of proposed sale to the public: From time
to time after this Registration Statement becomes effective as determined by
market conditions.
If the only securities being registered on this Form are being offered
pursuant to dividend or interest reinvestment plans, please check the following
box. [ ]
If any of the securities being registered on this Form are to be offered on
a delayed or continuous basis pursuant to Rule 415 under the Securities Act of
1933, other than securities offered only in connection with dividend or interest
reinvestment plans, check the following box. [X]
If this Form is filed to register additional securities for an offering
pursuant to Rule 462(b) under the Securities Act, please check the following box
and list the Securities Act Registration Statement number of the earlier
effective Registration Statement for the same offering. [ ]
If this Form is a post-effective amendment filed pursuant to Rule 462(c)
under the Securities Act, check the following box and list the Securities Act
Registration Statement number of the earlier effective Registration Statement
for the same offering. [ ]
If delivery of the prospectus is expected to be made pursuant to Rule 434,
please check the following box. [ ]
CALCULATION OF REGISTRATION FEE
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<TABLE>
<CAPTION>
Title of Securities to be Registered Amount to be Proposed Maximum Proposed Maximum Amount of
Registered Aggregate Price Per Unit Aggregate Offering Price Registration Fee/(3)/
<S> <C> <C> <C> <C>
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Rate Reduction Certificates $1,000,000 100%/(1)/ $1,000,000/(1)/ $303.03
- ------------------------------------------------------------------------------------------------------------------------------------
Notes $1,000,000/(2)/ /(2)/ /(2)/ None
====================================================================================================================================
</TABLE>
/(1)/ Estimated solely for the purpose of calculating the registration fee.
/(2)/ No additional consideration will be paid by the purchasers of the Rate
Reduction Certificates for the Notes which secure the Rate Reduction
Certificates.
/(3)/ Fee of $303.03 paid in connection with original Registration Statement
filed on July 3, 1997.
===============================================================================
The Registrant hereby amends this Registration Statement on such date or
dates as may be necessary to delay its effective date until the Registrant shall
file a further amendment which specifically states that this Registration
Statement shall thereafter become effective in accordance with Section 8(a) of
the Securities Act of 1933 or until this Registration Statement shall become
effective on such date as the Commission, acting pursuant to said Section 8(a),
may determine.
================================================================================
<PAGE>
Information contained herein is subject to completion or amendment. A
registration statement relating to these securities has been filed with the
Securities and Exchange Commission. These securities may not be sold nor may
offers to buy be accepted prior to the time the registration statement becomes
effective. This Prospectus Supplement shall not constitute an offer to sell or
the solicitation of an offer to buy nor shall there be any sale of the
securities in any jurisdiction in which such offer, solicitation or sale would
be unlawful prior to registration or qualification under the securities laws of
such jurisdiction.
[FORM OF PROSPECTUS SUPPLEMENT]
SUBJECT TO COMPLETION DATED ____, 199_
PROSPECTUS SUPPLEMENT
(TO PROSPECTUS DATED _______, 1997)
CALIFORNIA INFRASTRUCTURE AND ECONOMIC DEVELOPMENT BANK
SPECIAL PURPOSE TRUST PG&E-1
RATE REDUCTION CERTIFICATES, SERIES 199_-_
$__________ ORIGINAL PRINCIPAL BALANCE
[$________ CLASS ___ ____ % CERTIFICATES
$________ CLASS ___ ____ % CERTIFICATES
$________ CLASS ___ ____ % CERTIFICATES
$________ CLASS ___ ____ % CERTIFICATES
$________ CLASS ___ FLOATING RATE CERTIFICATES]
PG&E FUNDING LLC
Issuer of the Notes
PACIFIC GAS AND ELECTRIC COMPANY
Seller and Servicer
THE OFFERED CERTIFICATES DO NOT REPRESENT AN INTEREST IN OR OBLIGATION OF THE
STATE OF CALIFORNIA, THE INFRASTRUCTURE BANK, ANY OTHER GOVERNMENTAL AGENCY OR
INSTRUMENTALITY OR THE SELLER OR ANY OF ITS AFFILIATES, OTHER THAN THE NOTE
ISSUER. NONE OF THE OFFERED CERTIFICATES, THE UNDERLYING NOTES OR THE
TRANSITION PROPERTY WILL BE GUARANTEED OR INSURED BY THE STATE OF CALIFORNIA,
THE INFRASTRUCTURE BANK, THE TRUST OR ANY OTHER GOVERNMENTAL AGENCY OR
INSTRUMENTALITY OR BY THE SELLER OR ITS AFFILIATES.
The California Infrastructure and Economic Development Bank Special Purpose
Trust PG&E-1 Rate Reduction Certificates, Series 199_-_ (the "OFFERED
CERTIFICATES"), offered hereby will consist of the following ______ Classes:
_______. Each Class of Offered Certificates represents an undivided interest in
the related class of PG&E Funding LLC Notes, Series 199_-_ (the "UNDERLYING
NOTES"), issued by PG&E Funding LLC, a Delaware special purpose limited
liability company (the "NOTE ISSUER") [and, with respect to the Class _____
Certificates, payments pursuant to the Swap Agreement]. Each Underlying Note
will be secured primarily by the Transition Property owned by the Note Issuer,
as described under "Description of the Transition Property" herein and in the
Prospectus; the Underlying Notes will also be secured by the other Note
Collateral described under "Description of the Notes--Security" in the
Prospectus. The Underlying Notes, together with other Series of notes issued
from time to time by the Note Issuer under the Note Indenture (together with the
Underlying Notes, the "NOTES"), are owned by the California Infrastructure and
Economic Development Bank Special Purpose Trust PG&E-1 (the "Trust").
(Continued on following page.)
THERE CURRENTLY IS NO SECONDARY MARKET FOR THE OFFERED CERTIFICATES, AND THERE
IS NO ASSURANCE THAT ONE WILL DEVELOP.
PROSPECTIVE INVESTORS SHOULD CONSIDER, AMONG OTHER THINGS, THE INFORMATION SET
FORTH UNDER THE CAPTION "RISK FACTORS," WHICH BEGINS ON PAGE __ IN THE
PROSPECTUS.
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND
EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE SECURITIES
AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION PASSED UPON THE
ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS
A CRIMINAL OFFENSE.
<PAGE>
<TABLE>
<CAPTION>
- -----------------------------------------------------------------
PRICE TO UNDERWRITING PROCEEDS TO
PUBLIC(1) DISCOUNT TRUST(1)(2)
<S> <C> <C> <C>
- -----------------------------------------------------------------
Per Class [___] %
Certificate...... % %
- -----------------------------------------------------------------
Per Class [___] %
Certificate...... % %
- -----------------------------------------------------------------
Total............. $ $ $
- -----------------------------------------------------------------
</TABLE>
/(1)/ Plus accrued interest, if any, at the applicable Certificate Interest Rate
from ________ __, 199_.
/(2)/ Before deduction of expenses estimated to be $__________.
____________________
The Offered Certificates are offered by the Underwriters when, as and if
issued by the Trust and accepted by the Underwriters and subject to the
Underwriters' right to reject orders in whole or in part. It is expected that
the Offered Certificates will be delivered on or about ______________, 199__, in
book-entry form through the facilities of The Depository Trust Company[, Cedel
Bank, societe anonyme, and the Euroclear System].
____________________
[Underwriters]
The date of this Prospectus Supplement is _____, 199_
S-2
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Interest on each Class of Offered Certificates at the applicable Certificate
Interest Rate will be distributable quarterly on or about the 25th day of March,
June, September and December or, if any such day is not a Certificate Business
Day, the next succeeding Certificate Business Day (each, a "DISTRIBUTION DATE")
commencing _________, 199_. INTEREST AND PRINCIPAL ON ANY CLASS OF OFFERED
CERTIFICATES WILL BE DISTRIBUTABLE ONLY TO THE EXTENT OF PAYMENTS RECEIVED BY
THE TRUST ON THE RELATED CLASS OF UNDERLYING NOTES. See "Description of the
Notes" herein.
THIS PROSPECTUS SUPPLEMENT DOES NOT CONTAIN COMPLETE INFORMATION ABOUT THE
OFFERING OF THE OFFERED CERTIFICATES. ADDITIONAL INFORMATION IS CONTAINED IN THE
PROSPECTUS. PROSPECTIVE INVESTORS ARE URGED TO READ BOTH THIS PROSPECTUS
SUPPLEMENT AND THE PROSPECTUS IN FULL. SALES OF THE OFFERED CERTIFICATES MAY NOT
BE CONSUMMATED UNLESS THE PURCHASER HAS RECEIVED BOTH THIS PROSPECTUS SUPPLEMENT
AND THE PROSPECTUS.
THE TRANSITION PROPERTY OWNED BY THE NOTE ISSUER AND CERTAIN OTHER ASSETS OF THE
NOTE ISSUER ARE THE SOLE SOURCE OF PAYMENTS ON THE UNDERLYING NOTES. PAYMENTS
ON THE UNDERLYING NOTES RECEIVED BY THE TRUST ARE THE SOLE SOURCE OF
DISTRIBUTIONS ON THE OFFERED CERTIFICATES. NONE OF THE STATE OF CALIFORNIA, THE
INFRASTRUCTURE BANK, THE TRUST OR ANY OTHER GOVERNMENTAL AGENCY OR
INSTRUMENTALITY OR THE SELLER OR ANY OF ITS AFFILIATES WILL HAVE ANY OBLIGATIONS
IN RESPECT OF THE OFFERED CERTIFICATES, THE UNDERLYING NOTES OR THE TRANSITION
PROPERTY, EXCEPT AS EXPRESSLY SET FORTH HEREIN AND IN THE PROSPECTUS.
NEITHER THE FULL FAITH AND CREDIT NOR THE TAXING POWER OF THE STATE OF
CALIFORNIA OR ANY AGENCY OR INSTRUMENTALITY THEREOF IS PLEDGED TO THE PAYMENT OF
THE PRINCIPAL OF, OR INTEREST ON, THE UNDERLYING NOTES OR THE OFFERED
CERTIFICATES OR TO THE PAYMENTS IN RESPECT OF THE TRANSITION PROPERTY NOR IS THE
STATE OF CALIFORNIA OR ANY POLITICAL SUBDIVISION THEREOF IN ANY MANNER OBLIGATED
TO MAKE ANY APPROPRIATION FOR THE PAYMENT THEREOF.
Prospective investors should refer to the "Index of Principal Definitions" which
begins on page ___ herein and which begins on page ___ in the Prospectus for the
location of the definitions of capitalized terms that appear in the Prospectus
and this Prospectus Supplement.
S-3
<PAGE>
REPORTS TO HOLDERS
Unless and until the Offered Certificates are no longer issued in book-entry
form, the Servicer indirectly will provide to Cede & Co., as nominee of The
Depository Trust Company ("DTC") and registered holder of the Offered
Certificates and, upon request, to Participants of DTC, periodic reports
concerning the Offered Certificates. See "Description of the Certificates--
Reports to Certificateholders" herein. Such reports may be made available to
the holders of interests in the Offered Certificates (the "CERTIFICATEHOLDERS")
upon request to their Participants. Such reports will not constitute financial
statements prepared in accordance with generally accepted accounting principles.
The financial information provided to Certificateholders will not be examined
and reported upon, nor will an opinion thereon be provided by, any independent
public accountant.
The Note Issuer will file with the Securities and Exchange Commission (the
"COMMISSION") such periodic reports as are required by the Securities Exchange
Act of 1934, as amended (the "EXCHANGE ACT"), and the rules, regulations or
orders of the Commission thereunder. Copies of the Registration Statement and
exhibits thereto may be obtained at the locations specified in the Prospectus
under "Available Information" at prescribed rates. Information filed with the
Commission can also be inspected at the Commission's site on the World Wide Web
at http://www.sec.gov. The Note Issuer may discontinue filing periodic reports
under the Exchange Act at the beginning of the fiscal year following the
issuance of the Offered Certificates if there are fewer than 300 holders of such
Offered Certificates.
S-4
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S-5
<PAGE>
PROSPECTUS SUPPLEMENT SUMMARY
The summary is qualified in its entirety by reference to the detailed
information appearing elsewhere herein and in the Prospectus. Certain
capitalized terms used but not defined in this Prospectus Supplement Summary
have the meanings ascribed to such terms elsewhere in this Prospectus Supplement
or, to the extent not defined herein, have the meanings assigned to such terms
in the Prospectus. The Index of Principal Definitions included in this
Prospectus Supplement which begins on page ___ sets forth the pages on which the
definitions of certain principal terms appear.
Transaction Overview For a brief summary of the statutes and proceedings
which form the basis for the issuance and sale of the
Offered Certificates by the Trust, investors are
directed to the discussion under the heading
"Prospectus Summary--Transaction Overview" in the
Prospectus.
The Note Issuer will issue the Underlying Notes, which
will be secured by the Transition Property and the
other Note Collateral described under "Description of
the Notes--Security" herein, and sell the Underlying
Notes to the Trust in exchange for the proceeds of the
sale of the Offered Certificates. The Trust has been
established by the Infrastructure Bank. The Trust,
whose sole assets will be the Underlying Notes and
other Notes issued under the Indenture [and its rights
under the Swap Agreement (and any other comparable
interest rate swap agreements) to which it is a party],
will issue the Offered Certificates, which will be sold
to the Underwriters. The Offered Certificates of each
Class represent an undivided interest in the related
Class of Underlying Notes and the proceeds thereof [,
together with the proceeds of the Swap Agreement].
The charges included in the Transition Property
described in the Prospectus are calculated to be
sufficient over time to pay principal and interest on
the Offered Certificates, all related fees and expenses
and the Overcollateralization Amount described herein.
These charges will be subject to adjustment pursuant to
the true-up mechanism described in the Prospectus over
the life of the Offered Certificates to enhance the
likelihood of timely recovery of such amounts, although
there can be no assurance that the true-up mechanism
will operate as intended or that any of the Offered
Certificates will mature as scheduled.
S-6
<PAGE>
Risk Factors Investors should consider the risks associated with an
investment in the Offered Certificates. For a
discussion of certain material risks associated
therewith, investors should review the discussion under
"Risk Factors" which begins on page ___ of the
Prospectus.
[In addition, an investment in the Class ___
Certificates involves the additional risks discussed
herein under "Additional Risk Factors Relating to the
Class ___ Certificates."]
The Offered Certificates The California Infrastructure and Economic Development
Bank Special Purpose Trust PG&E-1 Rate Reduction
Certificates, Series 199_-_ (the "OFFERED
CERTIFICATES"). The Offered Certificates are comprised
of the following _____ classes (each, a "CLASS"):
_____. As of the Series Issuance Date for the Offered
Certificates, the aggregate principal balance thereof
(the "ORIGINAL CERTIFICATE PRINCIPAL BALANCE") will be
$___________. Each Class of Offered Certificates will
have a principal balance (the "CLASS PRINCIPAL
BALANCE") equal to the initial amount of principal
allocable to such Class, reduced by principal
distributed to such Class in accordance with the terms
of the Trust Agreement. See "Description of the
Certificates" herein and in the Prospectus.
None of the Offered Certificates, the Underlying Notes
or the Transition Property will be guaranteed or
insured by the State of California, the Infrastructure
Bank, the Trust or any other governmental agency or
instrumentality or by the Seller or any of its
affiliates. Neither the full faith and credit nor the
taxing power of the State of California or any agency
or instrumentality thereof is pledged to the
distributions of principal of, or interest on, the
Offered Certificates or the Underlying Notes or to the
payments in respect of the Transition Property. The
issuance and sale of the Offered Certificates is
contingent upon the effectiveness of the Issuance
Advice Letter related thereto.
Seller and Servicer Pacific Gas and Electric Company, a California
corporation ("PG&E" or, in its capacity as seller of
the Transition Property, the "SELLER" or, in its
capacity as servicer of the Transition Property, the
"SERVICER"). For a more complete discussion of PG&E
and its roles as Seller and Servicer, see "The Seller
and Servicer" herein and in the Prospectus.
Issuer of Certificates "California Infrastructure and Economic Development
Bank Special Purpose Trust PG&E-1" (the "TRUST")
established by the California Infrastructure and
Economic Development Bank (the "INFRASTRUCTURE BANK").
The Trust will not be an agency or instrumentality of
the State of California. The Infrastructure Bank will
not guarantee or insure the Offered Certificates,
the
S-7
<PAGE>
Underlying Notes or the Transition Property. For a
more complete discussion of the Trust, see "The Trust"
in the Prospectus, and for a more complete discussion
of the Infrastructure Bank, see "The Infrastructure
Bank" in the Prospectus.
Certificate Trustee ____________, a _________ (the "CERTIFICATE TRUSTEE").
Delaware Trustee ____________, a _________ (the "DELAWARE TRUSTEE").
Note Issuer PG&E Funding LLC, a Delaware special purpose limited
liability company whose single member is PG&E (the
"NOTE ISSUER").
The principal executive office of the Note Issuer is
located at 245 Market Street, Room 424, San Francisco,
California 94105, and its telephone number is (415)
972-5467.
The Underlying Notes PG&E Funding LLC Notes, Series 199_-_ (the "UNDERLYING
NOTES"), issued by the Note Issuer. The Underlying
Notes are comprised of ______ classes (each, a
"CLASS"). As of the Series Issuance Date for the
Underlying Notes, the aggregate principal balance
thereof (the "ORIGINAL NOTE PRINCIPAL BALANCE") will be
$___________. Each Class of Underlying Notes secures
the payment of the corresponding Class of Offered
Certificates and will have the same Class Principal
Balance as the corresponding Class of Offered
Certificates. See "Description of the Notes" herein
and in the Prospectus.
Note Trustee ____________, a _________ (the "NOTE TRUSTEE").
Transition Property As more fully described under "Description of the
Transition Property" herein and in the Prospectus, the
property right created under the PU Code including,
without limitation, the right, title and interest of an
electrical corporation or its transferee (i) in and to
the FTA Charges, as adjusted from time to time, (ii) to
be paid the FTA Payments, and (iii) to obtain
adjustments to the FTA Charges as provided in the PU
Code.
FTA Charges As more fully described under "Description of the
Transition Property" herein and in the Prospectus, the
amounts permitted to be recovered from the Customers
which are necessary to provide for the amortization of
all Certificates in accordance with the applicable
Expected Amortization Schedules, together with all
costs and expenses related thereto and the
Overcollateralization Amount.
Distribution Dates Each March 25, June 25, September 25 and December 25
(or, if any such date is not a Certificate Business
Day, the next succeeding Certificate Business Day),
commencing _________, 1998, the dates on which
distributions will be made to holders of Offered
Certificates (each, a "DISTRIBUTION DATE"). Each
S-8
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Distribution Date with respect to the Certificates will
also be a date on which payments are made with respect
to the Notes (each, a "PAYMENT DATE").
Record Date With respect to any Distribution Date, the last day of
the preceding calendar month (each, a "RECORD DATE").
Final Distribution Date The Scheduled Final Distribution Date for each Class of
the Offered Certificates, which is the date when all
principal and interest on such Class of Offered
Certificates is expected to be distributed in full,
based on certain assumptions described herein, and the
Termination Date for each Class of Offered Certificates
are specified herein under "Description of the
Certificates."
Failure to pay principal of and interest on any Class
of Offered Certificates in full by the related
Termination Date shall constitute an Event of Default,
and the Certificate Trustee may and, upon the written
direction of the holders of a majority in principal
amount of all Certificates of all Series then
outstanding, shall declare the unpaid principal amount
of all the Notes of all Series then outstanding to be
due and payable. See "Description of the Certificates-
-Certificate Events of Default; Rights Upon Certificate
Event of Default" and "Ratings" in the Prospectus.
Issuance of New Series The Trust may issue new Series of Certificates from
time to time. A new Series may be issued only upon
satisfaction of the conditions described under
"Description of the Certificates--Conditions of
Issuance of Additional Series" herein.
[Swap Agreement The Trust will enter into a swap agreement dated the
Closing Date (the "SWAP AGREEMENT") with ___________,
as swap counterparty (the "SWAP COUNTERPARTY").
Pursuant to the Swap Agreement, on each Distribution
Date, the Trust will be obligated to pay to the Swap
Counterparty, solely from payments received with
respect to the Class _ Notes, an amount equal to the
interest due on the Class ___ Notes on such
Distribution Date, and the Swap Counterparty will be
obligated to pay to the Trust an amount equal to the
product of the (a) Floating Rate and (b) the Class ___
Principal Balance as of the close of business on the
preceding Distribution Date after giving effect to all
payments of principal made to the Class ____
Certificateholders on such preceding Distribution
Date.]
The Swap Agreement will terminate or may be terminated
upon the occurrence of certain events of default or
termination events as described herein under "Summary
of Certain Provisions of the Swap Agreement." If, upon
or prior to the termination of the Swap Agreement, the
Infrastructure Bank, using its best efforts, is unable
to find a successor swap counterparty
S-9
<PAGE>
satisfying the requirements specified in the Trust
Agreement, the Certificate Interest Rate payable with
respect to the Class ___ Certificates will
automatically convert to a fixed rate equal to the
interest rate payable on the Class ____ Notes. See
"Description of the Certificates--Floating Rate on
Class ___ Certificates" and "Additional Risk Factors
Relating to the Class ____ Certificates."]
Interest On each Distribution Date, the Certificate Trustee
shall distribute pro rata to the Certificateholders of
each Class as of the related Record Date interest in an
amount equal to one-fourth of the product of (a) the
applicable Certificate Interest Rate and (b) the
applicable Class Principal Balance as of the close of
business on the preceding Distribution Date after
giving effect to all payments of principal made to the
Certificateholders on such preceding Distribution Date;
provided, however, that with respect to the initial
Distribution Date, interest on each outstanding Class
Principal Balance will accrue from and including the
Series Issuance Date to, but excluding, the following
Distribution Date. Interest will be calculated on the
basis of a 360-day year of twelve 30-day months [except
that with respect to the Class ___ Certificates
interest will be calculated as described under
"Description of the Certificates -- Floating Rate on
Class ___ Certificates."] Interest on any Class of
Offered Certificates will be payable only to the extent
interest has been paid on the related Class of
Underlying Notes [and, in the case of the Class ___
Certificates, interest will be paid based upon the
variable rate payable pursuant to the Swap Agreement
(the "Floating Rate") so long as payments are received
under the terms of the Swap Agreement]. See Description
of the Certificates--Distributions of Interest" herein
and "Description of the Certificates--Interest and
Principal" in the Prospectus.
Principal On each Distribution Date, the Certificate Trustee
shall distribute to the Certificateholders as of the
related Record Date amounts distributable as principal,
in the following order and priority: [TO BE DETERMINED
UPON ISSUANCE]. The principal amounts payable with
respect to any Class of Offered Certificates will be
payable only to the extent of payments of principal
made on the related Class of Underlying Notes. See
Description of the Certificates--Distributions of
Principal" herein and "Description of the Certificates-
-Interest and Principal" in the Prospectus.
Optional Redemption The Note Issuer may redeem the Underlying Notes
relating to the Offered Certificates, and accordingly
cause the Trust to redeem the Offered Certificates, if
the Outstanding Note Principal Balance has been reduced
to five percent of the Original Note Principal Balance.
See
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<PAGE>
"Description of the Certificates--Optional Redemption"
herein.
Collection Account
and Subaccounts Upon issuance of the initial Series of Notes, the Note
Issuer will establish the Collection Account, which
will be held by the Note Trustee for the benefit of the
Noteholders. The Collection Account will consist of
four subaccounts: a general subaccount (the "GENERAL
SUBACCOUNT"), a reserve subaccount (the "RESERVE
SUBACCOUNT"), a subaccount for the Over-
collateralization Amount (the "OVERCOLLATERALIZATION
SUBACCOUNT") and a capital subaccount (the "CAPITAL
SUBACCOUNT"). Unless the context indicates otherwise,
references herein to the Collection Account include
each of the subaccounts contained therein. Withdrawals
from and deposits to these subaccounts will be made as
described under "Description of the Notes--Allocations;
Payments" in the Prospectus.
Credit Enhancement The Offered Certificates will benefit from the
following forms of credit enhancement:
Overcollateralization. In order to enhance the
likelihood that distributions on each Class of the
Offered Certificates will be made in accordance with
their Expected Amortization Schedules, the Financing
Order and the Issuance Advice Letter relating to the
Offered Certificates permit the Seller to recover
$_______ through FTA Payments in excess of the amount
expected to be required to pay interest on and
principal of all outstanding Classes of Offered
Certificates and related fees and expenses. Such
excess is the Overcollateralization Amount related to
the Offered Certificates and will be allocated to the
Overcollateralization Subaccount, as described further
under "Description of the Notes--Overcollateralization
Amount" in the Prospectus, to be available to pay any
periodic shortfalls in amounts available for scheduled
payments on the Notes. See also "Description of the
--- ----
Notes--Overcollateralization Amount" herein.
Capital Subaccount. Upon the issuance of the
Underlying Notes, the Seller will make a capital
contribution of $___________ to the Note Issuer. Such
amount is equal to 0.50% of the initial principal
amount of the Underlying Notes. Such amount, less
$100,000 in the aggregate for all Series of Notes, is
the Required Capital Level with respect to the
Underlying Notes and will be deposited into the Capital
Subaccount. Withdrawals from and deposits to the
Capital Subaccount will be made as described under
"Description of the Notes--Allocations; Payments" in
the Prospectus.
S-11
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Reserve Subaccount. FTA Collections available with
respect to any Payment Date in excess of amounts
payable as (a) expenses of the Note Issuer and the
Trust, (b) payments of principal of and interest on the
Underlying Notes, (c) allocations to the
Overcollateralization Subaccount and (d) allocations to
the Capital Subaccount (all as described under
"Description of the Notes--Allocations; Payments" in
the Prospectus), will be allocated to the Reserve
Subaccount. On each Payment Date, the Note Trustee will
draw on amounts in the Reserve Subaccount, to the
extent amounts available in the General Subaccount are
insufficient to make scheduled payments on the
Underlying Notes.
Other. See "Description of the Certificates--Other
Credit Enhancement" herein and in the Prospectus.
Collections; Allocations;
Distributions On each Distribution Date, amounts on deposit in the
Collection Account will be applied in the manner
described under "Description of the Notes--
Allocations; Payments" in the Prospectus.
Servicing Compensation The Servicer will be entitled to receive a Servicing
Fee for each calendar quarter with respect to the
Offered Certificates in an amount equal to one-fourth
of [ ] percent per annum of the then outstanding
principal balance of the Underlying Notes (the
"SERVICING FEE"). The Servicing Fee will be paid prior
to the distribution of any amounts in respect of
interest on and principal of the Underlying Notes. The
Servicer will be entitled to retain as additional
compensation net investment income on FTA Payments
received by the Servicer prior to remittance thereof to
the Collection Account and the portion of late fees, if
any, paid by Customers relating to the Offered
Certificates. See "Servicing--Servicing Compensation"
herein and in the Prospectus.
No Servicer Advances The Servicer will not make any advances of interest or
principal on the Underlying Notes.
Maturity and Weighted
Average Life Considerations
The actual dates on which principal is distributed on each Class of
Certificates will be affected by, among other things, the amount and timing
of receipt of FTA Collections. Since each FTA Charge will consist of a
charge per kilowatt hour of usage by the applicable class of Customers in
the Territory, the aggregate amount and timing of FTA Collections (and the
resulting amount and timing of principal amortization on the Offered
Certificates) could depend, in part, on actual usage of electricity by
Customers and the rate of delinquencies and charge-offs. Although the
amount of the FTA Charges will adjust from time to time based in part on
the actual rate of FTA Collections during prior Billing Periods, no
assurances can be given that the Servicer will be able to forecast
accurately actual Customer energy usage and the rate of delinquencies and
charge-offs and implement adjustments to the FTA Charges that will
S-12
<PAGE>
cause FTA Payments to be made at any particular rate.
If FTA Collections are received at a slower rate than
expected, distributions on a Certificate may be made
later than expected. Because principal will only be
distributed in accordance with the Expected
Amortization Schedules, except in the event of an early
redemption, the Certificates are not expected to be
retired earlier than scheduled. See "Certain
Distribution and Weighted Average Life Considerations"
and "Description of the Transition Property--
Adjustments to the FTA Charges" in the Prospectus.
Denominations Each Class of Offered Certificates will be issued in
minimum initial denominations of [$1,000] and in
integral multiples thereof.
Registration of the
Certificates The [Offered] [Class ______] Certificates will
initially be represented by one or more certificates
registered in the name of Cede & Co. ("CEDE") ("BOOK-
ENTRY CERTIFICATES"), the nominee of The Depository
Trust Company ("DTC"), and available only in the form
of book-entries on the records of DTC, its Participants
and its Indirect Participants. For a more complete
discussion of the Book-Entry Certificates, see "Risk
Factors" and "Description of the Certificates--Book-
Entry Registration" in the Prospectus.
Ratings It is a condition of issuance of the Offered
Certificates that the Class ____ Certificates be rated
"____" by _______, "____" by _______ and "____" by
_______ (each of _______, ________ and _________, a
"RATING AGENCY") and that the Class _____ Certificates
be rated "____" by _______, "____" by _______ and
"____" by _______. Each Class of Underlying Notes will
receive the same rating from each Rating Agency as the
corresponding Class of Offered Certificates.
A security rating is not a recommendation to buy, sell
or hold securities and may be subject to revision or
withdrawal at any time. No person is obligated to
maintain any rating on any Offered Certificate and,
accordingly, there can be no assurance that the ratings
assigned to any Class of Offered Certificates upon
initial issuance thereof will not be revised or
withdrawn by a Rating Agency at any time thereafter.
If a rating of any Class of Offered Certificates is
revised or withdrawn, the liquidity of such Class of
Offered Certificates may be adversely affected. In
general, the ratings address credit risk and do not
represent any assessment of the rate of FTA
Collections. See "Risk Factors--
S-13
<PAGE>
Uncertain Distribution Amounts and Weighted Average
Life Considerations" in the Prospectus, "Certain
Distribution and Weighted Average Life Considerations"
herein and in the Prospectus and "Ratings" herein and
in the Prospectus.
Tax Status of the
Certificates The Offered Certificates will be treated as
representing ownership of debt for federal income tax
purposes. Interest and original issue discount, if
any, on the Offered Certificates generally will be
included in gross income for federal income tax
purposes. See "Certain Federal Income Tax
Consequences" in the Prospectus and herein.
Interest and original issue discount, if any, on the
Offered Certificates will be exempt from California
personal income tax, but not exempt from the California
franchise tax applicable to banks and corporations.
See "State Taxation" in the Prospectus and herein.
ERISA Considerations Subject to the considerations described in "ERISA
Considerations" herein and in the Prospectus, the
Offered Certificates are eligible for purchase with
"plan assets" of any Plan (as defined below) ("PLAN
ASSETS"). A fiduciary or other person contemplating
purchasing the Offered Certificates on behalf of or
with Plan Assets of any employee benefit plan or other
plan or arrangement (including but not limited to an
insurance company general account) that is subject to
Title I of the Employee Retirement Income Security Act
of 1974, as amended ("ERISA"), or Section 4975 of the
Internal Revenue Code of 1986, as amended (the "CODE")
(collectively, "PLANS"), should carefully review with
its legal advisors whether the purchase or holding of
the Offered Certificates could give rise to a
transaction prohibited or not otherwise permissible
under ERISA or Section 4975 of the Code.
S-14
<PAGE>
[ADDITIONAL RISK FACTORS RELATING TO THE CLASS ____ CERTIFICATES
As described herein under "Summary of Certain Provisions of the Swap
Agreement," upon the occurrence of certain events of default or termination
events, the Swap Agreement will terminate or may be terminated. Such
termination events include the right of the Infrastructure Bank and the
Certificate Trustee to terminate the Swap Agreement if the long-term unsecured
debt rating of the Swap Counterparty is withdrawn or suspended by either S&P or
Moody's or falls below the rating of "A" of either such Rating Agency. If the
Swap Agreement is terminated, the Infrastructure Bank will use its best efforts
to find a successor swap counterparty satisfying the qualifications described in
the Trust Agreement. If, upon or prior to such termination, the Infrastructure
Bank is unable to find such a successor swap counterparty, the Certificate
Interest Rate payable with respect to the Class __ Certificates will convert to
a fixed rate equal to the interest rate on the Class __ Notes, which is ______%.
Distributions of interest with respect to the Class ___ Certificates will
continue at this fixed interest rate until a successor swap counterparty has
been found, and no assurances are given that a successor swap counterparty will
be found. In such event, both the liquidity and the market value of the Class
___ Certificates may be adversely affected.]
DESCRIPTION OF THE CERTIFICATES
The California Infrastructure and Economic Development Bank Special Purpose
Trust PG&E-1 Rate Reduction Certificates, Series 199_-_ (the "OFFERED
CERTIFICATES") together with the Certificates of other Series issued by the
Trust (collectively, the "CERTIFICATES"), will be issued by the Trust pursuant
to the Trust Agreement and the Series 199_-_ Supplement thereto. Pursuant to
the Trust Agreement, the Infrastructure Bank and the Certificate Trustee may
execute further series supplements in order to issue additional Series of
Certificates. This summary should be read together with the material under the
heading "Description of the Certificates" in the Prospectus.
GENERAL
The Offered Certificates will be issued on the Series Issuance Date. The
Offered Certificates will be comprised of the following _____ Classes:
<TABLE>
<CAPTION>
Certificate
Scheduled Final Interest
Class Distribution Date Termination Date Rate
- ----- ----------------- ---------------- -----------
<S> <C> <C> <C>
___ ________, 200 (___ years) ______, 200 (___ years) __.__%
___ ________, 200 (___ years) ______, 200 (___ years) __.__%
___ ________, 200 (___ years) ______, 200 (___ years) __.__%
___ ________, 200 (___ years) ______, 200 (___ years) __.__%
___ ________, 200 (___ years) ______, 200 (___ years) __.__% /(1)/
</TABLE>
/(1)/ Calculated as described under "Floating Rate on Class ___
Certificates."
[FLOATING RATE ON CLASS __ CERTIFICATES
(i) Determination of Class ___ Certificate Interest Rate. The
---------------------------------------------------------
Certificate Interest Rate applicable from time to time to Class __ Certificates
will be determined by the _______________(together with any successor Agent Bank
under the Trust Agreement the "AGENT BANK") in accordance with the following
provisions:
(a) On the second London banking day immediately preceding the first
day of each Interest Accrual Period (as defined below) and on the Closing
Date with respect to the first Interest Accrual Period (each such day, an
"INTEREST DETERMINATION DATE"), the Agent Bank will determine
S-15
<PAGE>
"LIBOR" based on the offered rate for deposits in U.S. dollars for a period
of [three months] commencing on the first day of such Interest Accrual
Period that appears on the display page of the Dow Jones Telerate
Service for the purpose of displaying the London Interbank offered rate of
major banks for U.S. Dollars as of 11:00 a.m., London time, on such
Interest Determination Date (such display page being the "TELERATE PAGE").
Notwithstanding the foregoing, if no offered rate appears, LIBOR for such
Interest Accrual Period will be determined as if the parties had specified
the rate described in clause (b) below. The Certificate Interest Rate
applicable to the Class ___ Certificates for the Interest Accrual Period
relating to an Interest Determination Date shall be the sum of LIBOR as
determined by the Agent Bank on the most recent Interest Determination Date
plus _____%.
(b) With respect to an Interest Determination Date on which no
offered rate appears on the Telerate Page, the Agent Bank will request the
principal London office of each of four major banks in the London interbank
market, selected by the Agent Bank (after consultation with the
Infrastructure Bank), to provide the Agent Bank with its offered quotation
for deposits in U.S. Dollars for a period of three months, commencing on
the second London banking day immediately following such Interest
Determination Date, to prime banks in the London interbank market at
approximately 11:00 a.m., London time, on such Interest Determination Date
and in a principal amount that is representative for a single transaction
in U.S. Dollars in such market at such time. If at least two such
quotations are provided, LIBOR for the relevant Interest Accrual Period
will be the arithmetic mean of such quotations. If fewer than two
quotations are provided, LIBOR for such Interest Accrual Period will be the
arithmetic mean of the rates quoted at approximately 11:00 a.m. in The City
of New York, on such Interest Determination Date by three major banks in
The City of New York selected by the Agent Bank (after consultation with
the Infrastructure Bank) for loans in U.S. Dollars to leading European
banks, for the period of three months, commencing on the second London
banking day immediately following such Interest Determination Date and in a
principal amount that is representative for a single transaction in U.S.
Dollars in such market at such time; provided, however, that if any of the
banks so selected by the Agent Bank are not quoting as mentioned in this
sentence, the Certificate Interest Rate in effect for such Interest Accrual
Period will be the rate of interest in effect on such Interest
Determination Date.
(c) Subject to applicable usury laws, there will be no maximum or
minimum Certificate Interest Rate.
Notwithstanding the foregoing, in the event that the Swap Agreement has been
terminated, and the Swap Counterparty has not been replaced with a successor
swap counterparty satisfying the requirements of the Trust Agreement, the
interest rate with respect to the Class __ Certificates shall be __ % per annum
(calculated on the basis of a 360-day year consisting of twelve 30-day months),
effective as of the first day of the Interest Accrual Period immediately
preceding the termination of the Swap Agreement.
(ii) Calculation of Quarterly Interest. The Agent Bank will, as soon
---------------------------------------
as practicable after 11:00 a.m. (London time) on each Interest Determination
Date, determine the Certificate Interest Rate applicable to, and calculate the
amount of interest payable on, each of the Class __ Certificates for the
relevant Interest Accrual Period. Interest payments will be made in an amount
equal to the product of (a)(1) the actual number of days in the related Interest
Accrual Period (as defined herein) divided by 360, multiplied by (2) the
applicable Certificate Interest Rate and (b) the Class __ Principal Balance (as
defined herein) as of the close of business day on the preceding Distribution
Date after giving effect to all payments of principal made to the Class __
Certificateholders on such preceding Distribution Date (or, in the case of the
first Distribution Date, as of the Closing Date) (such amount, the "Quarterly
Interest" with respect to such Class). The "INTEREST ACCRUAL PERIOD" with
S-16
<PAGE>
respect to any Distribution Date shall be the period from and including the
preceding Distribution Date (or, in the case of the first Distribution Date,
from and including the Closing Date) to and excluding such Distribution Date.
The determination of the Certificate Interest Rate and the Quarterly Interest by
the Agent Bank shall (in the absence of manifest error) be final and binding
upon all parties.
(iii) Notice of Certificate Interest Rate and Interest Payments. The
----------------------------------------------------------------
Agent Bank will notify the Infrastructure Bank, the Certificate Trustee and any
Paying Agents of the Certificate Interest Rate and the Quarterly Interest due on
the Class __ Certificates for each Interest Accrual Period and the relevant
Distribution Date as soon as possible after their determination but in no event
later than the [first] business day of any Interest Accrual Period.
(iv) Determination or Calculation by Certificate Trustee. If the
---------------------------------------------------------
Agent Bank fails to determine a Certificate Interest Rate or calculate Quarterly
Interest in accordance with paragraph (ii) above at any time or for any reason,
the Certificate Trustee shall determine the Certificate Interest Rate and
calculate the Quarterly Interest in accordance with paragraph (ii) above, and
each such determination or calculation shall be deemed to have been made by the
Agent Bank. The determination by the Agent Bank or the Certificate Trustee (as
the case may be) of any Certificate Interest Rate and calculation thereby of any
Quarterly Interest shall, in the absence of manifest error, be final and binding
on all parties.
(v) Agent Bank. The Infrastructure Bank will agree that, so long as
---------------
any of the Certificates remain outstanding, there will at all times be an Agent
Bank. The Infrastructure Bank may (with the prior written approval of the
Certificate Trustee) terminate the appointment of the Agent Bank for any reason.
Notice of any such termination will be given to Certificateholders within ten
days of such termination. If (a) any person is unable or unwilling to continue
to act as the Agent Bank, (b) the appointment of the Agent Bank is terminated or
(c) the Agent Bank fails duly to determine the Certificate Interest Rate and/or
the Quarterly Interest for any Interest Accrual Period, then the Infrastructure
Bank will, with the approval of the Certificate Trustee, appoint a successor
Agent Bank to act as such in its place, provided that neither the resignation
nor removal of the Agent Bank shall take effect until a successor approved by
the Certificate Trustee has been appointed. Notice of any such appointment of a
successor Agent Bank will be given to the Certificateholders within ten days of
such appointment.]
DISTRIBUTIONS OF INTEREST
Interest on each Class of the Offered Certificates will accrue from the
Series Issuance Date at the rates indicated above (each, a "CERTIFICATE INTEREST
RATE"), in each case distributable quarterly on March 25, June 25, September 25
and December 25 (or, if any such date is not a Certificate Business Day, the
next succeeding Certificate Business Day) each year (each, a "DISTRIBUTION
DATE"), commencing _________.
On each Distribution Date, the Certificate Trustee will distribute pro rata
to the Certificateholders of each Class as of the related Record Date interest
to the extent paid on such date with respect to the Class of Underlying Notes
with the same alphabetical [and numeric] designation, as described below under
"Description of the Notes--Distributions of Interest" or, with respect to the
Class ___ Certificates, payments received from the Swap Counterparty pursuant to
the Swap Agreement.
DISTRIBUTIONS OF PRINCIPAL
On each Distribution Date, the Certificate Trustee will distribute pro rata
to the Certificateholders of each Class as of the related Record Date principal
to the extent paid on such date with respect to the Class of Underlying Notes
S-17
<PAGE>
with the same alphabetical [and numeric] designation, as described below under
"Description of the Notes--Principal."
The entire unpaid principal amount of the Offered Certificates will be due
and distributable on the date on which a Certificate Event of Default has
occurred and is continuing, if the Certificate Trustee or holders of a majority
in principal amount of the Offered Certificates of all Series then outstanding
have declared the Certificates to be immediately due and payable. See
"Description of the Certificates--Certificate Events of Default; Rights Upon
Certificate Event of Default" in the Prospectus.
OPTIONAL REDEMPTION
The Trust shall be required to redeem the Offered Certificates if the Note
Issuer elects to redeem the Underlying Notes, which the Note Issuer may elect to
do at any time on or after the Payment Date on which the Outstanding Note
Principal Balance has been reduced to five percent of the Original Note
Principal Balance. Such Payment Date will correspond to the Distribution Date
on which the Outstanding Certificate Principal Balance has been reduced to five
percent of the Original Certificate Principal Balance. Notice of such
redemption will be given by the Trust to each holder of Certificates to be
redeemed by first-class mail, postage prepaid, mailed not less than five days
nor more than 25 days prior to the date of redemption.
SUMMARY OF CERTAIN PROVISIONS OF THE SERIES __
SUPPLEMENT TO THE TRUST AGREEMENT
[TO BE PREPARED UPON ISSUANCE]
[SUMMARY OF CERTAIN PROVISIONS OF THE SWAP AGREEMENT]
[TO BE PREPARED UPON ISSUANCE]
[THE SWAP COUNTERPARTY]
[TO BE PREPARED UPON ISSUANCE]
DESCRIPTION OF THE NOTES
GENERAL
The PG&E Funding LLC Notes, Series 199_-_ (the "UNDERLYING NOTES"), will be
issued by the Note Issuer to the Trust on ______________ (the "SERIES ISSUANCE
DATE"), pursuant to the Note Indenture and the Series 199_-_ Supplement thereto.
Pursuant to the Note Indenture, the Note Issuer and the Note Trustee may execute
further series supplements in order to issue additional Series of Notes. This
summary should be read together with the material under the heading "Description
of the Notes" in the Prospectus.
S-18
<PAGE>
The Underlying Notes, together with the Notes of other Series issued by the
Note Issuer (collectively, the "NOTES"), will be issued pursuant to the Note
Indenture. The Underlying Notes will be comprised of the following _____
Classes:
<TABLE>
<CAPTION>
Note
Scheduled Interest
Class Maturity Date Final Maturity Date Rate
- ----- ------------- ------------------- ----
<S> <C> <C> <C>
___ ________, 200 (___ years) ______, 200 (___ years) __.__%
___ ________, 200 (___ years) ______, 200 (___ years) __.__%
___ ________, 200 (___ years) ______, 200 (___ years) __.__%
___ ________, 200 (___ years) ______, 200 (___ years) __.__%
___ ________, 200 (___ years) ______, 200 (___ years) __.__%
</TABLE>
SECURITY
To secure the payment of principal of and interest on the Notes, the Note
Issuer has granted to the Note Trustee, for the benefit of the holders of the
Notes (the "NOTEHOLDERS"), a security interest in all of the Note Issuer's
right, title and interest in and to the Note Collateral. The Note Collateral is
described more specifically under "Description of the Notes--Security" in the
Prospectus.
INTEREST
Interest on each Class of the Underlying Notes will accrue from the Series
Issuance Date at the rates indicated above (each, a "Note Interest Rate"), in
each case payable quarterly on March 25, June 25, September 25 and December 25
(or, if any such date is not a Certificate Business Day, the next succeeding
Certificate Business Day) each year (each, a "PAYMENT DATE"), commencing
_________, to the persons in whose names the Underlying Notes are registered at
the close of business on the related Record Date.
On each Payment Date, Noteholders of each Class will be entitled to receive
an amount equal to one-fourth of the product of (a) the applicable Note Interest
Rate and (b) the applicable Class Principal Balance as of the close of business
on the preceding Distribution Date after giving effect to all payments of
principal made to the Noteholders on such preceding Distribution Date; provided,
however, that with respect to the initial Distribution Date, interest on each
outstanding Class Principal Balance will accrue from and including the Series
Issuance Date to but excluding the following Distribution Date. Interest will
be calculated on the basis of a 360-day year of twelve 30-day months. See
"Description of the Notes--Interest and Principal" in the Prospectus.
PRINCIPAL
On each Payment Date, each Class of the Underlying Notes will be entitled
to receive payments of principal as follows: [TO BE PREPARED UPON ISSUANCE].
Principal will be payable at the Corporate Trust Office of the Note Trustee in
the City of _______, or at the office or agency of the Note Issuer maintained
for such purposes in the Borough of Manhattan, the City of New York.
The following Expected Amortization Schedule sets forth the scheduled
outstanding percentage of the initial Class Principal Balance for each Class of
the Underlying Notes at each Payment Date from the Series Issuance Date to the
Scheduled Maturity Date for such Class. In preparing the following table, it
has been assumed that (i) the Offered Certificates are issued on the Series
Issuance Date, (ii) payments on the Offered Certificates are made on each
Distribution Date, commencing _______________, 199_, (iii) the initial Class
____ Principal Balance is $_____ and the initial Class ____ Principal
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<PAGE>
Balance is $______, (iv) all FTA Collections are deposited in the Collection
Account in accordance with the Seller's forecasts, (v) the Note Issuer does not
redeem the Underlying Notes and ( ) [other assumptions].
EXPECTED AMORTIZATION SCHEDULE
Percentage of Initial Class
Principal Balance Outstanding
Payment -----------------------------
Date Class Class Class Class Class
- ---- ------- ------- ------- ------- -------
Initial Percentage
_____, 199_
_____, 199_
_____, 199_
[Etc.]
There can be no assurance that the Class Principal Balances of the
Underlying Notes and the related Offered Certificates will be reduced at the
rates indicated in the foregoing table, and the actual reductions in such Class
Principal Balances may be slower than those indicated in the chart. See "Risk
Factors" in the Prospectus for a discussion of various factors which may,
individually or in the aggregate, affect the rate of reductions of the Class
Principal Balances of the Underlying Notes and the Offered Certificates.
The entire unpaid principal amount of the Underlying Notes will be due and
payable on the date on which a Note Event of Default has occurred and is
continuing, if the Note Trustee or holders of a majority in principal amount of
the Notes of all Series then outstanding have declared the Underlying Notes to
be immediately due and payable. See "Description of the Notes--Note Events of
Default; Rights Upon Note Event of Default" in the Prospectus.
OPTIONAL REDEMPTION
The Note Issuer may redeem, at its option, the Underlying Notes, and
accordingly cause the Trust to redeem the Offered Certificates, at any time on
or after the Payment Date on which the Outstanding Note Principal Balance has
been reduced to five percent of the Original Note Principal Balance. Notice of
such redemption will be given by the Note Issuer to each holder of Underlying
Notes by first-class mail, postage prepaid, mailed not less than five days nor
more than 25 days prior to the date of redemption.
OVERCOLLATERALIZATION AMOUNT
In order to enhance the likelihood that distributions on each Class of the
Offered Certificates will be made in accordance with their Expected Amortization
Schedules, the Financing Order and the Issuance Advice Letter relating to the
Offered Certificates permit the recovery of $_______ through FTA Payments in
excess of the amount expected to be required to pay interest on and principal of
all outstanding Classes of Offered Certificates and related fees and expenses.
Such excess is the Overcollateralization Amount related to the Offered
Certificates and will be allocated to the Overcollateralization Subaccount, as
described further under "Description of the Notes--Overcollateralization Amount"
in the Prospectus, to be available to pay any periodic shortfalls in amounts
available for scheduled payments on the Notes.
OTHER CREDIT ENHANCEMENT
Capital Subaccount. Upon the issuance of the Underlying Notes, the Seller
------------------
will make a capital contribution of $___________ to the Note Issuer. Such
amount is equal to 0.50% of the initial principal amount of the
S-20
<PAGE>
Underlying Notes. Such amount, less $100,000 in the aggregate for all Series of
Notes, is the Required Capital Level with respect to the Underlying Notes and
will be deposited into the Capital Subaccount. Withdrawals from and deposits to
the Capital Subaccount will be made as described under "Description of the
Notes--Allocations; Payments" in the Prospectus.
RESERVE SUBACCOUNT. FTA Collections available with respect to any Payment
Date in excess of amounts payable as (a) expenses of the Note Issuer and the
Trust, (b) payments of principal of and interest on the Underlying Notes, (c)
allocations to the Overcollateralization Subaccount and (d) allocations to the
Capital Subaccount (all as described under "Description of the Notes--
Allocations; Payments" in the Prospectus), will be allocated to the Reserve
Subaccount. On each Payment Date, the Note Trustee will draw on amounts in the
Reserve Subaccount, to the extent amounts available in the General Subaccount
are insufficient to make scheduled payments on the Underlying Notes.
[OTHER TO BE PREPARED UPON ISSUANCE]
ALLOCATIONS; PAYMENTS
On each Payment Date, the Note Trustee will at the direction of the
Servicer apply all amounts on deposit in the Collection Account with respect to
the prior Billing Period in the manner described under "Description of the
Notes--Allocations; Payments" in the Prospectus.
The Certificate Trustee will then apply all amounts paid by the Note
Trustee on the related Payment Date with respect to the Underlying Notes in the
following priority:
[TO BE PREPARED UPON ISSUANCE]
DESCRIPTION OF THE TRANSITION PROPERTY
FINANCING ORDER AND ADVICE LETTERS
The Financing Order requires the Seller to submit an Issuance Advice Letter
to the CPUC with respect to each Series of Certificates issued. The first
Issuance Advice Letter [, which was filed in connection with the Offered
Certificates,] established the FTA Charges pursuant to which nonbypassable
charges will be billed to the applicable classes of Customers in an amount
sufficient to recover, within the time period specified in the Issuance Advice
Letter, FTA Charges designated in the Issuance Advice Letter based on factors
including, but not limited to, the actual electricity usage of each such
Customer and the rate of delinquencies and charge-offs. These charges are
nonbypassable in that applicable consumers cannot avoid paying them if they
purchase electricity from a supplier other than the Seller. [Subsequent
Issuance Advice Letters have modified the FTA Charges to support the issuance of
______ additional Series of Certificates, including the Offered
Certificates.]
The Issuance Advice Letter which was filed in connection with the Offered
Certificates establishes the following FTA Charges:
S-21
<PAGE>
Class of Customers
- ------------------
FTA Charge Per Kilowatt Hour
- ----------------------------
Residential
Small Commercial
As of the date hereof, the FTA Charge for an average Residential Customer
will amount to approximately $____ per month, and the FTA Charge for an average
Small Commercial Customer will amount to approximately $____ per month. The
average monthly bill, excluding local taxes, during 1996 was ______ for a
Residential Customer and _____ for a Small Commercial Customer.
ADJUSTMENTS TO THE FTA CHARGES
In order to enhance the likelihood that the FTA Collections are neither
more nor less than the amount necessary to amortize the Certificates in
accordance with the Expected Amortization Schedule, the Servicing Agreement and
the Financing Order require the Servicer to seek periodic adjustments to the FTA
Charges based on actual FTA Collections and updated assumptions by the Servicer
as to, among other factors, the electricity usage by Customers and the rate of
delinquencies and charge-offs. The date as of which any calculation is
performed which forms the basis for a requested adjustment to the FTA Charges is
referred to as a "CALCULATION DATE." The adjustments to the FTA Charges will
continue until all interest and principal on all Series of Notes and
corresponding Series of Certificates have been paid or distributed in full.
[The following table reflects information regarding the changes to the FTA
Charges which have been requested through Advice Letters since the Financing
Order was issued:
FTA CHARGE FOR RESIDENTIAL CUSTOMERS
<TABLE>
<CAPTION>
Requested Adjustment Resulting
Adjustment to FTA Charge Aggregate
Calcu- to FTA Charge Granted by CPUC FTA Charge Effective
lation per per per Date of
Date Kilowatt Hour Kilowatt Hour Kilowatt Hour Adjustment
- --------- ------------- --------------- ------------- ----------
<S> <C> <C> <C> <C>
[TO BE PREPARED UPON ISSUANCE]
</TABLE>
FTA CHARGE FOR SMALL COMMERCIAL CUSTOMERS
<TABLE>
<CAPTION>
Requested Adjustment Resulting
Adjustment to FTA Charge Aggregate
Calcu- to FTA Charge Granted by CPUC FTA Charge Effective
lation per per per Date of
Date Kilowatt Hour Kilowatt Hour Kilowatt Hour Adjustment
- --------- ------------- --------------- ------------- ----------
<S> <C> <C> <C> <C>
[TO BE PREPARED UPON ISSUANCE]
]
</TABLE>
S-22
<PAGE>
See "Description of the Transition Property--Adjustments to the FTA
Charges" in the Prospectus.
CERTAIN DISTRIBUTION AND WEIGHTED AVERAGE LIFE CONSIDERATIONS
The rate of principal distributions on each Class of Offered Certificates,
the aggregate amount of each interest distribution on each Class of Offered
Certificates and the actual maturity date of each Class of Offered Certificates
will be related to the rate and timing of FTA Collections.
The actual distributions on each date for each Class of Offered
Certificates and the weighted average life thereof will be affected primarily by
the rate of FTA Collections and the timing of receipt of such FTA Collections.
Since the FTA Charges will consist of a charge per kilowatt hour of usage by the
applicable classes of Customers, the aggregate amount of FTA Collections and the
rate of principal amortization on the Offered Certificates will depend, in part,
on actual energy usage by Customers and the rate of delinquencies and charge-
offs. Although the amounts of the FTA Charges will be adjusted from time to
time based in part on the actual rate of FTA Collections, no assurances are
given that the Servicer will be able to forecast accurately actual energy usage
and the rate of delinquencies and charge-offs or implement adjustments to the
FTA Charges that will cause FTA Collections to be received at any particular
rate. If FTA Collections are received at a slower rate than expected an Offered
Certificate may be retired later than expected. Because principal will only be
distributed in accordance with the Expected Amortization Schedules, except in
the event of an early redemption, the Offered Certificates are not expected to
mature earlier than scheduled. A distribution on a date that is earlier than
forecasted will result in a shorter weighted average life, and a distribution on
a date that is later than forecasted will result in a longer weighted average
life. In addition, if a larger portion of the delayed distributions on the
Offered Certificates are received in later years, this will result in a longer
weighted average life of the Offered Certificates.
No representation is made as to the particular factors that will affect the
rate of FTA Collections, as to the relative importance of such factors, as to
the percentage of the principal balance of the Offered Certificates that will be
distributed as of any date or as to the overall rate of FTA Collections.
THE SELLER AND SERVICER
S-23
<PAGE>
The following is information which supplements that provided under the
heading "The Seller and Servicer" in the Prospectus. For a more complete
discussion of the Seller and Servicer, see "The Seller and Servicer" in the
Prospectus.
Pacific Gas and Electric Company reported net income of $_________ on
revenues of $_________ for the [quarter][year] ended ________, 199_, as compared
with net income of $_________ on revenues of $_________ for the [quarter][year]
ended ________, 199_.
SERVICING
GENERAL
The Servicer, as agent for the Note Issuer, will manage, service and
administer, and make collections in respect of, the Transition Property pursuant
to the Servicing Agreement between the Servicer and the Note Issuer. For a
detailed discussion of the Servicer's procedures, the manner in which payments
from Customers are remitted to the Collection Account, and related matters, see
"Servicing" in the Prospectus.
NO SERVICER ADVANCES
The Servicer will not make any advances of interest or principal on the
Underlying Notes.
SERVICING COMPENSATION
The Servicer will be entitled to receive the Servicing Fee for each Billing
Period, in an amount equal to one-fourth of ___ percent per annum of the
Outstanding Note Principal Balance. The Servicing Fee (together with any
portion of the Servicing Fee that remains unpaid from prior Distribution Dates)
will be paid solely to the extent funds are available therefor as described
under "Description of the Notes--Allocations; Payments" in the Prospectus. The
Servicing Fee will be paid prior to the distribution of any amounts in respect
of interest on and principal of the Underlying Notes. The Servicer will be
entitled to retain as additional compensation net investment income on FTA
Payments received by the Servicer prior to remittance thereof to the Collection
Account and the portion of late fees, if any, paid by Customers relating to the
FTA Payments.
AGGREGATORS AND ALTERNATIVE ENERGY SUPPLIERS
As part of the deregulation of the California electric industry described
in the Prospectus, there will be an unbundling of generation, transmission,
distribution and billing services. A decision of the CPUC allows alternative
energy service providers ("ESPS") to elect to present a consolidated bill to
their retail customers, including the FTA Charges. Any ESP who elects
consolidated billing, including monthly amounts with respect to the FTA Charges,
will be responsible for paying the Servicer periodic amounts payable by
customers of the ESP. Neither the Seller nor the Servicer will pay any
shortfalls resulting from the failure of any ESPs to forward FTA Payments to
PG&E, as Servicer, which may result in delays in distributions to
Certificateholders. See "Risk Factors--Potential Servicing Issues--Reliance on
Aggregators and Other Suppliers" in the Prospectus.
S-24
<PAGE>
STATEMENTS BY SERVICER
For each Remittance Date and each Distribution Date, the Servicer will
provide the statements and reports described under "Servicing--Statements by
Servicer" in the Prospectus.
S-25
<PAGE>
CERTAIN FEDERAL INCOME TAX CONSEQUENCES
Interest on the Offered Certificates will be included in gross income for
federal income tax purposes.
GENERAL
The following is a general discussion of material federal income tax
consequences relating to the purchase, ownership and disposition of an Offered
Certificate, and is based on the opinion of Brown & Wood LLP, counsel to the
Trust ("SPECIAL COUNSEL"). This discussion represents the opinion of Special
Counsel, subject to the qualifications set forth therein or herein. This
discussion is based on current provisions of the Internal Revenue Code of 1986,
as amended (the "CODE"), currently applicable Treasury regulations and judicial
and administrative rulings and decisions. Legislative, judicial or
administrative changes may be forthcoming that could alter or modify the
statements and conclusions set forth herein. Any such changes or
interpretations may or may not be retroactive and could affect tax consequences
to Offered Certificateholders.
The discussion does not address all of the tax consequences relevant to a
particular Offered Certificateholder in light of that Offered
Certificateholder's circumstances, and some Offered Certificateholders may be
subject to special tax rules and limitations not discussed below (e.g., life
insurance companies, tax-exempt organizations, financial institutions or broker-
dealers). CONSEQUENTLY, EACH PROSPECTIVE OFFERED CERTIFICATEHOLDER IS URGED TO
CONSULT ITS OWN TAX ADVISER IN DETERMINING THE FEDERAL, STATE, LOCAL AND FOREIGN
INCOME AND ANY OTHER TAX CONSEQUENCES OF THE PURCHASE, OWNERSHIP AND DISPOSITION
OF AN OFFERED CERTIFICATE.
For purposes of this discussion, "U.S. PERSON" means a citizen or resident
of the United States, a corporation or partnership created or organized in the
United States, or under the law of the United States or of any state thereof
(including the District of Columbia), an estate the income of which is
includible in gross income for U.S. federal income tax purposes regardless of
its source, or a trust if a court within the United States is able to exercise
primary supervision over the administration of the trust and one or more United
States persons has the authority to control all substantial decisions of the
trust (or, under certain circumstances, a trust the income of which is
includible in gross income for U.S federal income tax purposes regardless of its
source). The term "U.S. OFFERED CERTIFICATEHOLDER" means any U.S. Person and
any other person to the extent that income attributable to its interest in an
Offered Certificate is effectively connected with that person's conduct of a
U.S. trade or business. The term "NON-U.S. OFFERED CERTIFICATEHOLDER" means any
person other than a U.S. Offered Certificateholder.
The discussion assumes that an Offered Certificate is issued in registered
form, has all payments denominated in U.S. dollars and not determined by
reference to the value of any other currency and has a term that exceeds one
year. Moreover, the discussion assumes that any original issue discount ("OID")
on the Offered Certificate (i.e., any excess of the stated redemption price at
maturity of the Offered Certificate over its issue price) is less than a de
minimis amount (i.e., 0.25 percent of its stated redemption price at maturity
multiplied by the Offered Certificate's weighted average maturity), all within
the meaning of the OID regulations. Moreover, the discussion assumes that the
Offered Certificates are of a type, as set forth below, which Special Counsel is
of the opinion will represent ownership of debt for federal income tax
purposes.
TREATMENT OF THE OFFERED CERTIFICATES AS DEBT
Special Counsel has rendered an opinion to the effect that, for federal
income tax purposes, the Offered Certificates will represent ownership of
debt
S-26
<PAGE>
and the Trust will not be treated as an association or publicly traded
partnership taxable as a corporation.
TAXATION OF INTEREST INCOME OF U.S. OFFERED CERTIFICATEHOLDERS
General. Assuming, in accordance with Special Counsel's opinion, that the
-------
Offered Certificates represent ownership of debt obligations for federal income
tax purposes, stated interest on a beneficial interest in an Offered Certificate
will be taxable as ordinary income when received or accrued by U.S. Offered
Certificateholders in accordance with their method of accounting. Generally,
interest received on the Offered Certificates will constitute "investment
income" for purposes of certain limitations of the Code concerning the
deductibility of investment interest expense.
Market Discount. A U.S. Offered Certificateholder who purchases (including
---------------
a purchase at original issuance for a price less than the issue price) an
interest in an Offered Certificate at a discount that exceeds any unamortized
OID may be subject to the "market discount" rules of sections 1276 through 1278
of the Code. These rules generally provide that, subject to a statutorily-
defined de minimis exception, if a U.S. Offered Certificateholder acquires an
Offered Certificate at a market discount (i.e., at a price below its stated
redemption price at maturity or its revised issue price if it was issued with
OID) and thereafter recognizes gain upon a disposition of the Offered
Certificate (or disposes of it in certain non-recognition transactions,
including by gift), the lesser of such gain (or appreciation, in the case of an
applicable non-recognition transaction) or the portion of the market discount
that accrued while the Offered Certificate was held by such holder will be
treated as ordinary interest income at the time of the disposition. In
addition, a U.S. Offered Certificateholder who acquired an Offered Certificate
at a market discount would be required to treat as ordinary interest income the
portion of any principal payment attributable to accrued market discount on such
Offered Certificate. Generally, market discount accrues ratably over the life
of a debt instrument unless the debt holder elects to accrue market discount on
a constant yield to maturity basis. It is not clear how either the ratable
accrual or constant yield accrual methodologies apply to instruments such as the
Offered Certificates where the timing of principal payments is uncertain.
Investors should consult their own tax advisors concerning the accrual of market
discount. The market discount rules also provide that a U.S. Offered
Certificateholder who acquires an Offered Certificate at a market discount may
be required to defer a portion of any interest expense that otherwise may be
deductible on any indebtedness incurred or maintained to purchase or carry the
Offered Certificate until the holder disposes of the Offered Certificate in a
taxable transaction.
A U.S. Offered Certificateholder who acquired an Offered Certificate at a
market discount may elect to include market discount in income as the discount
accrues, either on a ratable basis or, if elected, on a constant yield basis.
The current inclusion election, once made, applies to all market discount
obligations acquired on or after the first day of the first taxable year to
which the election applies, and may not be revoked without the consent of the
Internal Revenue Service (the "IRS"). If a holder elects to include market
discount in income in accordance with the preceding sentence, the foregoing
rules with respect to the recognition of ordinary income on sales, principal
payments and certain other dispositions of the Offered Certificates and the
deferral of interest deductions on indebtedness related to the investor
certificates will not apply.
Amortizable Bond Premium. A U.S. Offered Certificateholder who purchases
------------------------
an interest in an Offered Certificate at a premium may elect to offset the
premium against interest income under the constant yield method over the
remaining term of the Offered Certificate in accordance with the provisions of
section 171 of the Code. A holder that elects to amortize bond premium must
reduce the tax basis in the related Offered Certificate by the amount of bond
premium used to offset interest income. If an Offered Certificate purchased at
a premium is redeemed in full prior to its maturity,
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<PAGE>
a holder who has elected to amortize bond premium should be entitled to a
deduction in the taxable year of redemption in an amount equal to the excess, if
any, of the adjusted basis of the Offered Certificate over the greater of the
redemption price or the amount payable on maturity.
SALE OR EXCHANGE OF OFFERED CERTIFICATES
Upon a disposition of an interest in an Offered Certificate, a U.S. Offered
Certificateholder generally will recognize gain or loss equal to the difference
between (i) the amount of cash and the fair market value of any other property
received (other than amounts attributable to, and taxable as, accrued stated
interest) and (ii) the U.S. Offered Certificateholder's adjusted basis in its
interest in the Offered Certificate. The adjusted basis in the interest in the
Offered Certificate will equal its cost, increased by any OID or market discount
included in income with respect to the interest in the Offered Certificate prior
to its disposition and reduced by any payments reflecting principal or OID
previously received with respect to the interest in the Offered Certificate and
any amortized premium. Subject to the OID and market discount rules, gain or
loss will generally be capital gain or loss if the interest in the Offered
Certificate was held as a capital asset. Capital losses generally may be used
by a corporate taxpayer only to offset capital gains and by an individual
taxpayer only to the extent of capital gains plus $3,000 of other income.
NON-U.S. OFFERED CERTIFICATEHOLDERS
In general, a non-U.S. Offered Certificateholder will not be subject to
U.S. federal income tax on interest (including OID) on a beneficial interest in
an Offered Certificate unless (i) the non-U.S. Offered Certificateholder
actually or constructively owns 10 percent or more of the total combined voting
power of all classes of stock of the Seller entitled to vote (or of a profits or
capital interest of the Trust characterized as a partnership), (ii) the non-U.S.
Offered Certificateholder is a controlled foreign corporation that is related to
the Seller (or the Trust treated as a partnership) through stock ownership,
(iii) the non-U.S. Offered Certificateholder is a bank which receives interest
as described in Code Section 881(c)(3)(A), (iv) such interest is contingent
interest described in Code Section 871(h)(4), or (v) the non-U.S. Offered
Certificateholder bears certain relationships to any holder of either the Notes
other than the transferor or any other interest in the Trust not properly
characterized as debt. To qualify for the exemption from taxation, the last
U.S. Person in the chain of payment prior to payment to a non-U.S. Offered
Certificateholder (the "WITHHOLDING AGENT") must have received (in the year in
which a payment of interest or principal occurs or in either of the two
preceding years) a statement that (i) is signed by the non-U.S. Offered
Certificateholder under penalties of perjury, (ii) certifies that the non-U.S.
Offered Certificateholder is not a U.S. Person and (iii) provides the name and
address of the non-U.S. Offered Certificateholder. The statement may be made on
a Form W-8 or substantially similar substitute form, and the non-U.S. Offered
Certificateholder must inform the Withholding Agent of any change in the
information on the statement within 30 days of the change. If an Offered
Certificate is held through a securities clearing organization or certain other
financial institutions, the organization or institution may provide a signed
statement to the Withholding Agent. However, in that case, the signed statement
must be accompanied by a Form W-8 or substitute form provided by the non-U.S.
Offered Certificateholder to the organization or institution holding the Offered
Certificate on behalf of the non-U.S. Offered Certificateholder. The U.S.
Treasury Department is considering implementation of further certification
requirements aimed at determining whether the issuer of a debt obligation is
related to holders thereof.
Generally, any gain or income realized by a non-U.S. Offered
Certificateholder upon retirement or disposition of an interest in an Offered
Certificate (other than gain attributable to accrued interest or OID, which is
addressed in the preceding paragraph) will not be subject to U.S. federal income
tax, provided that in the case of an Offered Certificateholder that is
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<PAGE>
an individual, such Offered Certificateholder is not present in the United
States for 183 days or more during the taxable year in which such retirement or
disposition occurs. Certain exceptions may be applicable, and an individual
non-U.S. Offered Certificateholder should consult a tax adviser.
INFORMATION REPORTING AND BACKUP WITHHOLDING
Backup withholding of U.S. federal income tax at a rate of 31 percent may
apply to payments made in respect of an Offered Certificate to a registered
owner who is not an "exempt recipient" and who fails to provide certain
identifying information (such as the registered owner's taxpayer identification
number) in the manner required. Generally, individuals are not exempt
recipients whereas corporations and certain other entities are exempt
recipients. Payments made in respect of a U.S. Offered Certificateholder must
be reported to the IRS, unless the U.S. Offered Certificateholder is an exempt
recipient or otherwise establishes an exemption.
In the case of payments of principal of and interest on (and the amount of
OID, if any, accrued on) investor certificates to non-U.S. Offered
Certificateholders, temporary Treasury regulations provide that backup
withholding and information reporting will not apply to payments with respect to
which either requisite certification has been received or an exemption has
otherwise been established (provided that neither the Certificate Trustee nor a
paying agent has actual knowledge that the holder is a United States Person or
that the conditions of any other exemption are not in fact satisfied). Payments
of the proceeds of the sale of an Offered Certificate to or through a foreign
office of a broker that is a U.S. Person, a controlled foreign corporation for
United States federal income tax purposes or a foreign person 50% or more of
whose gross income is effectively connected with the conduct of a trade or
business within the United States for a specified three-year period are
currently subject to certain information reporting requirements, unless the
payee is an exempt recipient or such broker has evidence in its records that the
payee is not a U.S. Person and no actual knowledge that such evidence is false
and certain other conditions are met. Temporary Treasury regulations indicate
that such payments are not currently subject to backup withholding. Under
current Treasury regulations, payments of the proceeds of a sale to or through
the United States office of a broker will be subject to information reporting
and backup withholding unless the payee certifies under penalties of perjury as
to his or her status as a non-U.S. Person and certain other qualifications (and
no agent of the broker who is responsible for receiving or reviewing such
statement has actual knowledge that it is incorrect) and provides his or her
name and address or the payee otherwise establishes an exemption.
Any amounts withheld under the backup withholding rules from a payment to
an Offered Certificateholder would be allowed as a refund or a credit against
such Offered Certificateholder's U.S. federal income tax, provided that the
required information is furnished to the IRS.
STATE TAXATION
CALIFORNIA TAXATION
In the opinion of Special Counsel, interest and OID on the Offered
Certificates will be exempt from California personal income tax, but not exempt
from the California franchise tax applicable to banks and corporations. Gain or
loss, if any, resulting from an exchange or redemption of Offered Certificates
will be recognized in the year of the exchange or redemption. Present
California law taxes both long-term and short-term capital gains at the rates
applicable to ordinary income. Interest on indebtedness incurred or continued
by an Offered Certificateholder in connection with the purchase of Offered
Certificates will not be deductible for California personal income tax
purposes.
S-29
<PAGE>
OTHER STATES
The discussion above does not address the taxation of the Trust or the tax
consequences of the purchase, ownership or disposition of an interest in the
Offered Certificates under any state or local tax law other than that of the
State of California. Each investor should consult its own tax adviser regarding
state and local tax consequences.
ERISA CONSIDERATIONS
GENERAL
The Employee Retirement Income Security Act of 1974, as amended ("ERISA"),
and/or Section 4975 of the Code impose certain requirements on employee benefit
plans and certain other plans and arrangements, including individual retirement
accounts and annuities, Keogh plans and certain collective investment funds or
insurance company general or separate accounts in which such plans, accounts or
arrangements are invested, that are subject to the fiduciary responsibility and
prohibited transaction provisions of ERISA and/or Section 4975 of the Code
(collectively, "PLANS"), and on persons who are fiduciaries with respect to
Plans, in connection with the investment of assets that are treated as "plan
assets" of any Plan for purposes of applying Title I of ERISA and Section 4975
of the Code ("PLAN ASSETS"). ERISA imposes on Plan fiduciaries certain general
fiduciary requirements, including those of investment prudence and
diversification and the requirement that a Plan's investments be made in
accordance with the documents governing the Plan. Generally, any person who has
discretionary authority or control respecting the management or disposition of
Plan Assets, and any person who provides investment advice with respect to Plan
Assets for a fee or other consideration, is a fiduciary with respect to such
Plan Assets.
Subject to the considerations described below, the Offered Certificates are
eligible for purchase with Plan Assets of any Plan.
ERISA and Section 4975 of the Code prohibit a broad range of transactions
involving Plan Assets and persons who have certain specified relationships to a
Plan or its Plan Assets ("parties in interest" under ERISA and "disqualified
persons" under the Code (collectively, "PARTIES IN INTEREST")), unless a
statutory or administrative exemption is available. Parties in Interest and
Plan fiduciaries that participate in a prohibited transaction may be subject to
penalties imposed under ERISA and/or excise taxes imposed pursuant to Section
4975 of the Code, unless a statutory or administrative exemption is available.
These prohibited transaction rules generally are set forth in Section 406 of
ERISA and Section 4975 of the Code.
Any fiduciary or other Plan investor considering whether to purchase the
Offered Certificates of any Class on behalf of or with Plan Assets of any Plan
should determine whether such purchase is consistent with its fiduciary duties
and whether such purchase would constitute or result in a non-exempt prohibited
transaction under ERISA and/or Section 4975 of the Code because any of PG&E, the
Certificate Trustee, the Underwriters or their respective affiliates may be
deemed to be benefiting from the issuance of the Offered Certificates and is a
Party in Interest with respect to the investing Plan. In particular, the
Offered Certificates may not be purchased with Plan Assets of any Plan if any of
PG&E, the Certificate Trustee, the Underwriters or their respective affiliates
(a) has investment or administrative discretion with respect to the Plan Assets
used to effect such purchase; (b) has authority or responsibility to give, or
regularly gives, investment advice with respect to such Plan Assets, for a fee
and pursuant to an agreement or understanding that such advice (1) will serve as
a primary basis for investment decisions with respect to such Plan Assets, and
(2) will be based on the particular investment needs of such Plan; or (c) is an
employer maintaining or contributing to such Plan. Each purchaser of the
Offered Certificates will be deemed to have represented and warranted that its
purchase of the Offered
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<PAGE>
Certificates or any interest therein does not violate the foregoing limitations.
PLAN ASSET REGULATION
Because the Offered Certificates are likely to be treated as "equity
interests" in the Trust under a regulation (the "PLAN ASSET REGULATION") issued
by the U.S. Department of Labor (the "DOL"), which provides that beneficial
interests in a trust are equity interests, purchasing the Offered Certificates
with Plan Assets may cause the assets of the Trust to be deemed Plan Assets of
the investing Plan which, in turn, would subject the Trust and its assets to the
fiduciary responsibility provisions of ERISA and the prohibited transaction
provisions of ERISA and Section 4975 of the Code. A violation of the prohibited
transaction rules could occur if the Offered Certificates are purchased with
Plan Assets of any Plan and any of PG&E, the Certificate Trustee, the
Underwriters or their respective affiliates is a Party in Interest with respect
to such Plan, unless a statutory or administrative exemption is available or an
exception applies under the Plan Asset Regulation. However, the possibility
that prohibited transactions may occur by reason of the operation of the Trust
is substantially less than in other pass-through trusts because each Class of
Offered Certificates represents an interest in the corresponding Class of
Underlying Notes and only minimal administrative activity is expected to occur
at the Trust level.
Before purchasing any Class of Offered Certificates of this Series, a
fiduciary or other Plan investor should consider whether a prohibited
transaction might arise by reason of any such relationship between the investing
Plan and any of PG&E, the Certificate Trustee, the Underwriters or their
respective affiliates and consult its legal advisors regarding the purchase in
light of the considerations described herein and in the Prospectus. The DOL has
issued six class exemptions that may afford exemptive relief for otherwise
prohibited transactions arising from the purchase or holding of the Offered
Certificates, i.e., DOL Prohibited Transaction Exemptions 96-23 (Class Exemption
for Plan Asset Transactions Determined by In-House Investment Managers), 95-60
(Class Exemption for Certain Transactions Involving Insurance Company General
Accounts), 91-38 (Class Exemption for Certain Transactions Involving Bank
Collective Investment Funds), 90-1 (Class Exemption for Certain Transactions
Involving Insurance Company Pooled Separate Accounts), 84-14 (Class Exemption
for Plan Asset Transactions Determined by Independent Qualified Professional
Asset Managers), and 75-1 (Part III) (Class Exemption for Certain Underwriting
Transactions). A purchaser of the Offered Certificates should be aware,
however, that even if the conditions specified in one or more of the above
exemptions are met, the scope of the relief provided by the exemption might not
cover all acts which might be construed as prohibited transactions.
CONCLUSION
In light of the foregoing, fiduciaries or other Plan investors considering
whether to purchase the Offered Certificates with Plan Assets of any Plan should
consult their own legal advisors regarding whether the Trust assets would be
considered Plan Assets of Plan investors, the consequences that would apply if
the Trust's assets were considered Plan Assets, and the availability of
exemptive relief from the prohibited transaction rules or an exception under the
Plan Asset Regulation. Fiduciaries and other Plan investors should also
consider the fiduciary standards under ERISA or other applicable law in the
context of the Plan's particular circumstances before authorizing an investment
of a Plan Assets in the Offered Certificates. Among other factors, such persons
should consider whether the investment (a) satisfies the diversification
requirement of ERISA or other applicable law, (b) is in accordance with the
Plan's governing instruments, and (c) is
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<PAGE>
prudent in light of the "Risk Factors" and other factors discussed herein and in
the Prospectus.
For further information see "ERISA Considerations" in the Prospectus.
UNDERWRITING
Subject to the terms and conditions set forth in the Underwriting
Agreement, the Trust has agreed to sell to each of the Underwriters named below
(the "UNDERWRITERS"), and each of the Underwriters, for whom ______________ are
acting as representatives, has severally agreed to purchase, the respective
principal amounts of the Offered Certificates set forth opposite its name
below.
<TABLE>
<CAPTION>
Principal
Amount of
Name Certificates
- ---- ------------
<S> <C>
[Underwriter].................................$ $
[Underwriter].................................$ $
[Underwriter].................................$ $
[Others]......................................$
------------
Total....................................$ $
</TABLE>
Under the terms and conditions of the Underwriting Agreement, the
Underwriters are committed to take and to pay for all of the Offered
Certificates offered hereby, if any are taken.
The Underwriters propose to offer the Offered Certificates in part directly
to retail purchasers at the initial public offering price set forth on the cover
page of this Prospectus Supplement, and in part to certain securities dealers at
such price less a concession not in excess of _____ percent of the principal
amount of the Offered Certificates. The Underwriters may allow and such dealers
may reallow a concession not in excess of _____ percent of the principal amount
of the Offered Certificates to certain brokers and dealers. After the Offered
Certificates are released for sale to the public, the offering price and other
selling terms may from time to time be varied by the Underwriters.
The Offered Certificates are a new issue of securities with no established
trading market. [The Certificates will not be listed on any securities
exchange.] The Trust has been advised by the Underwriters that they intend to
make a market in the Offered Certificates but are not obligated to do so and may
discontinue market making at any time without notice. No assurance can be given
as to the liquidity of the trading market for the Offered Certificates.
The Note Issuer and the Seller have agreed to indemnify the several
Underwriters against certain liabilities, including liabilities under the
Securities Act.
RATINGS
It is a condition of issuance of the Offered Certificates that the Class
____ Certificates be rated "____" by _______, "____" by _______ and "____" by
_______ (each of _______, ________ and _________, a "RATING AGENCY") and that
the Class _____ Certificates be rated "____" by _______, "____" by _______ and
"____" by _______. Each Class of Underlying Notes will receive the same ratings
from each Rating Agency as the corresponding Class of Offered Certificates.
A security rating is not a recommendation to buy, sell or hold securities
and may be subject to revision or withdrawal at any time by the
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<PAGE>
assigning Rating Agency. No person is obligated to maintain the rating on any
Offered Certificate, and, accordingly, there can be no assurance that the
ratings assigned to any Class of Offered Certificates upon initial issuance will
not be revised or withdrawn by a Rating Agency at any time thereafter. If a
rating of any Class of Offered Certificates is revised or withdrawn, the
liquidity of such Class of Offered Certificates may be adversely affected. In
general, ratings address credit risk and do not represent any assessment of the
rate of FTA Payments.
LEGAL MATTERS
Certain legal matters relating to the Underlying Notes and certain federal
income tax consequences of the issuance of the Underlying Notes will be passed
upon by Orrick, Herrington & Sutcliffe LLP, San Francisco, California, counsel
to the Seller and the Note Issuer. Certain legal matters relating to the
Offered Certificates and certain federal income tax consequences of the issuance
of the Offered Certificates will be passed upon by Special Counsel. Certain
legal matters relating to the Offered Certificates will be passed upon by
Cravath, Swaine & Moore, New York, New York, counsel to the Underwriters.
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<PAGE>
INDEX OF PRINCIPAL DEFINITIONS
------------------------------
Set forth below is a list of the defined terms used in this Prospectus
Supplement and defined herein and the pages on which the definitions of such
terms may be found herein. Certain defined terms used in this Prospectus
Supplement are defined in the Prospectus. See "Index of Principal Definitions"
in the Prospectus.
<TABLE>
<S> <C>
A-1 Notes...................................................... S-3
Agent Bank..................................................... S-14
Book-Entry Certificates........................................ S-12
Calculation Date............................................... S-21
Capital Subaccount............................................. S-10
Cede........................................................... S-12
Certificate Interest Rate...................................... S-16
Certificate Trustee............................................ S-6
Certificateholders............................................. S-4
Certificates................................................... S-14
Class.......................................................... S-6, S-7
Class Principal Balance........................................ S-6
Code........................................................... S-24
Distribution Date.............................................. S-3, S-7, S-16
DTC............................................................ S-4, S-12
Exchange Act................................................... S-4
General Subaccount............................................. S-9
Infrastructure Bank............................................ S-6
Interest Accrual Period........................................ S-15
Interest Determination Date.................................... S-14
IRS............................................................ S-25
Non-U.S. Certificateholder..................................... S-24
Note Issuer.................................................... S-1, S-7
Note Trustee................................................... S-7
Noteholder..................................................... S-18
Notes.......................................................... S-18
Offered Certificates........................................... S-1, S-6, S-14
OID............................................................ S-24
Original Certificate Principal Balance......................... S-6
Original Note Principal Balance................................ S-7
Overcollateralization Subaccount............................... S-10
Payment Date................................................... S-7, S-18
PG&E........................................................... S-6
Rating Agency.................................................. S-12, S-30
Record Date.................................................... S-7
Reserve Subaccount............................................. S-9
Seller......................................................... S-6
Series Issuance Date........................................... S-17
Servicer....................................................... S-6
Servicing Fee.................................................. S-11
Special Counsel................................................ S-24
Swap Agreement................................................. S-8
Swap Counterparty.............................................. S-8
Telerate Page.................................................. S-15
Trust.......................................................... S-6
U.S. Certificateholder......................................... S-24
U.S. Person.................................................... S-24
Underlying Notes............................................... S-1, S-7, S-17
Underwriters................................................... S-30
Withholding Agent.............................................. S-26
</TABLE>
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<PAGE>
++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++
Information contained herein is subject to completion or amendment. A
registration statement relating to these securities has been filed with the
Securities and Exchange Commission. These securities may not be sold nor may
offers to buy be accepted prior to the time the registration statement becomes
effective. This Prospectus shall not constitute an offer to sell or the
solicitation of an offer to buy nor shall there be any sale of the securities in
any jurisdiction in which such offer, solicitation or sale would be unlawful
prior to registration or qualification under the securities laws of such
jurisdiction.
++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++
SUBJECT TO COMPLETION DATED [___], 1997
PROSPECTUS
CALIFORNIA INFRASTRUCTURE AND ECONOMIC DEVELOPMENT BANK
SPECIAL PURPOSE TRUST PG&E-1
RATE REDUCTION CERTIFICATES
ISSUABLE IN SERIES
----------------
PG&E Funding LLC
Issuer of the Notes
----------------
Pacific Gas and Electric Company
Seller and Servicer
THE CERTIFICATES DO NOT REPRESENT AN INTEREST IN OR OBLIGATION OF THE STATE OF
CALIFORNIA, THE INFRASTRUCTURE BANK, ANY OTHER GOVERNMENTAL AGENCY OR
INSTRUMENTALITY OR THE SELLER OR ANY OF ITS AFFILIATES, OTHER THAN THE NOTE
ISSUER. NONE OF THE CERTIFICATES, THE NOTES OR THE UNDERLYING TRANSITION
PROPERTY WILL BE GUARANTEED OR INSURED BY THE STATE OF CALIFORNIA, THE
INFRASTRUCTURE BANK, THE TRUST OR ANY OTHER GOVERNMENTAL AGENCY OR
INSTRUMENTALITY OR BY THE SELLER OR ITS AFFILIATES.
The California Infrastructure and Economic Development Bank Special Purpose
Trust PG&E-1 Rate Reduction Certificates (the "CERTIFICATES") offered hereby in
an aggregate principal amount of up to $__________ may be sold from time to time
in series (each, a "SERIES"), each of which may be comprised of one or more
classes (each, a "CLASS"), as described in the related Prospectus Supplement.
Each Series of Certificates will be issued by the California Infrastructure and
Economic Development Bank Special Purpose Trust PG&E-1 (the "TRUST") established
by the California Infrastructure and Economic Development Bank (the
"INFRASTRUCTURE BANK").
The assets of the Trust will consist solely of the PG&E Funding LLC Notes (the
"NOTES") issued by PG&E Funding LLC, a Delaware special purpose limited
liability company (the "NOTE ISSUER"), and the proceeds thereof. The sole
member of the Note Issuer is Pacific Gas and Electric Company, a California
corporation ("PG&E"). The Notes will be secured primarily by the Transition
Property, as described under "Prospectus Summary--Transition Property" and
"Description of the Transition Property" herein; the Notes will also be secured
by the other Note Collateral described under "Description of the Notes--
Security" herein.
PG&E will sell the Transition Property (in such capacity, the "SELLER") to the
Note Issuer pursuant to the Transition Property Purchase and Sale Agreement
between the Seller and the Note Issuer. See "Description of the Transition
Property--Sale and Assignment of Transition Property" herein. The Seller will
also service the Transition Property (in its capacity as servicer, the
"SERVICER") pursuant to the Transition Property Servicing Agreement between the
Servicer and the Note Issuer. See "Servicing" herein.
The Note Issuer will issue Notes from time to time in series to the Trust, and
the Trust will issue to investors separate Series of Certificates from time to
time upon terms determined at the time of sale and described in the related
Prospectus Supplement. Each Series of Notes (each, a "SERIES") may be issuable
in one or more classes (each, a "CLASS"). A Series may include Classes which
differ as to the interest rate, timing, sequential order and amount of
distributions of principal or interest or both or otherwise. As more
specifically described under "Description of the Notes--Allocations; Payments"
<PAGE>
herein, the Note Issuer will use all payments made with respect to Transition
Property to pay certain expenses described herein, interest due on the Notes and
principal payable on the Notes, allocated among the Series and Classes of Notes
based on the priorities described herein and in the related Prospectus
Supplement. All principal not previously paid, if any, on any Note is due and
payable on the Final Maturity Date of such Note. Each Class of Certificates
will correspond to a Class of Notes and will represent undivided interests in
such underlying Class of Notes, the proceeds thereof and payments pursuant to
any related Swap Agreement. As such, each Class of Certificates will entitle
the holders thereof to receive the payments received by the Trust in respect of
the corresponding Class of Notes. The funds received by the Trust from the
payments on each Class of Notes will be the only source of distributions on the
Certificates of the corresponding Class. While the specific terms of any Series
of Certificates (and the Classes, if any, thereof) will be described in the
related Prospectus Supplement, the terms of such Series and any Classes thereof
will not be subject to prior review by, or consent of, the holders of the
Certificates of any previously issued Series.
Offers of the Certificates of a Series may be made through one or more different
methods, including offerings through underwriters, as described under "Plan of
Distribution" herein and "Underwriting" in the related Prospectus Supplement.
There will have been no secondary market for the Certificates of any Series
prior to the offering thereof. There can be no assurance that a secondary
market for any Series of Certificates will develop or, if one does develop, that
it will continue. It is not anticipated that any of the Certificates will be
listed on any securities exchange.
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND
EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE SECURITIES
AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION PASSED UPON THE
ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS
A CRIMINAL OFFENSE.
PROSPECTIVE INVESTORS SHOULD CONSIDER, AMONG OTHER THINGS, THE INFORMATION SET
FORTH UNDER THE CAPTION "RISK FACTORS," WHICH BEGINS ON PAGE _______ HEREIN.
THE TRANSITION PROPERTY OWNED BY THE NOTE ISSUER AND CERTAIN OTHER ASSETS OF THE
NOTE ISSUER WILL BE THE SOLE SOURCE OF PAYMENTS ON THE NOTES. PAYMENTS ON THE
NOTES RECEIVED BY THE TRUST ARE THE SOLE SOURCE OF DISTRIBUTIONS ON THE
CERTIFICATES. NONE OF THE STATE OF CALIFORNIA, THE INFRASTRUCTURE BANK, THE
TRUST OR ANY OTHER GOVERNMENTAL AGENCY OR INSTRUMENTALITY OR THE SELLER OR ITS
AFFILIATES WILL HAVE ANY OBLIGATIONS IN RESPECT OF THE CERTIFICATES, THE NOTES
OR THE TRANSITION PROPERTY, EXCEPT AS EXPRESSLY SET FORTH HEREIN OR IN THE
RELATED PROSPECTUS SUPPLEMENT.
NEITHER THE FULL FAITH AND CREDIT NOR THE TAXING POWER OF THE STATE OF
CALIFORNIA OR ANY AGENCY OR INSTRUMENTALITY THEREOF IS PLEDGED TO THE
DISTRIBUTIONS OF PRINCIPAL OF, OR INTEREST ON, THE CERTIFICATES OR THE NOTES OR
TO THE PAYMENTS IN RESPECT OF THE TRANSITION PROPERTY NOR IS THE STATE OF
CALIFORNIA OR ANY
2
<PAGE>
POLITICAL SUBDIVISION THEREOF IN ANY MANNER OBLIGATED TO MAKE ANY APPROPRIATION
FOR THE PAYMENT THEREOF.
THIS PROSPECTUS MAY NOT BE USED TO CONSUMMATE SALES OF SECURITIES OFFERED HEREBY
UNLESS ACCOMPANIED BY THE RELATED PROSPECTUS SUPPLEMENT.
Prospective investors should refer to the "Index of Principal Definitions" which
begins on page ___ herein for the location of the definitions of capitalized
terms that appear in this Prospectus.
__________ __, 1997
3
<PAGE>
No dealer, salesperson, or any other person has been authorized to give any
information, or to make any representations, other than those contained in this
Prospectus or the related Prospectus Supplement and, if given or made, such
information or representations must not be relied upon as having been authorized
by the Seller, the Note Issuer, the Trust, the Infrastructure Bank or any
dealer, salesperson, or any other person. Neither the delivery of this
Prospectus or the related Prospectus Supplement nor any sale made hereunder or
thereunder shall under any circumstances create an implication that there has
been no change in the information herein or therein since the date hereof. This
Prospectus and the related Prospectus Supplement do not constitute an offer to
sell or a solicitation of an offer to buy any security in any jurisdiction in
which it is unlawful to make such offer or solicitation.
UNTIL 90 DAYS AFTER THE DATE OF EACH PROSPECTUS SUPPLEMENT, ALL
DEALERS EFFECTING TRANSACTIONS IN THE RELATED SERIES OF CERTIFICATES, WHETHER OR
NOT PARTICIPATING IN THE DISTRIBUTION THEREOF, MAY BE REQUIRED TO DELIVER THIS
PROSPECTUS AND THE RELATED PROSPECTUS SUPPLEMENT. THIS DELIVERY REQUIREMENT IS
IN ADDITION TO THE OBLIGATION OF DEALERS TO DELIVER A PROSPECTUS SUPPLEMENT AND
PROSPECTUS WHEN ACTING AS UNDERWRITERS AND WITH RESPECT TO THEIR UNSOLD
ALLOTMENTS OR SUBSCRIPTIONS.
AVAILABLE INFORMATION
The Note Issuer has filed with the Securities and Exchange Commission (the
"COMMISSION") a registration statement (as amended, the "REGISTRATION
STATEMENT") under the Securities Act of 1933, as amended (the "SECURITIES ACT"),
with respect to the Certificates and the Notes. This Prospectus, which forms a
part of the Registration Statement, and any Prospectus Supplement describe the
material terms of each document filed as an exhibit to the Registration
Statement; however, this Prospectus and any Prospectus Supplement do not contain
all of the information contained in the Registration Statement and the exhibits
thereto. Any statements contained herein concerning the provisions of any
document filed as an exhibit to the Registration Statement or otherwise filed
with the Commission are not necessarily complete, and in each instance reference
is made to the copy of such document so filed. Each such statement is qualified
in its entirety by such reference. For further information, reference is made
to the Registration Statement and the exhibits thereto, which are available for
inspection without charge at the public reference facilities maintained by the
Commission at 450 Fifth Street, N.W., Washington, D.C. 20549, and at its
regional offices located as follows: Chicago Regional Office, Citicorp Center,
500 West Madison Street, Suite 1400, Chicago, Illinois 60661-2511; and New York
Regional Office, 7 World Trade Center, 13th Floor, New York, New York 10048.
Copies of the Registration Statement and exhibits thereto may be obtained at the
above locations at prescribed rates. Information filed with the Commission can
also be inspected at the Commission's site on the World Wide Web at
http://www.sec.gov.
The Note Issuer will file with the Commission such periodic reports with
respect to each Series of Certificates as are required by the Securities
Exchange Act of 1934, as amended (the "EXCHANGE ACT"), and the rules,
regulations or orders of the Commission thereunder. The Note Issuer may
discontinue filing periodic reports under the Exchange Act at the beginning of
the fiscal year following the issuance of the Certificates of any Series if
there are fewer than 300 holders of such Certificates.
REPORTS TO HOLDERS
Unless and until the Certificates are no longer issued in book-entry form,
the Servicer will provide to Cede & Co., as nominee of The Depository Trust
Company ("DTC") and registered holder of the Certificates and, upon request, to
Participants of DTC, periodic reports concerning the Certificates. See
"Description of the Certificates--Reports to Certificateholders" herein. Such
reports may be made available to the holders of interests in the Certificates
(the "CERTIFICATEHOLDERS") upon request to their Participants. Such reports
will not constitute financial statements prepared in accordance with generally
accepted accounting principles. The financial information provided to
4
<PAGE>
Certificateholders will not be examined and reported upon, nor will an opinion
thereon be provided, by any independent public accountant.
INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE
All reports and other documents filed by the Note Issuer pursuant to
Sections 13(a), 13(c), 14 or 15(d) of the Exchange Act subsequent to the date of
this Prospectus and prior to the termination of the offering made hereby shall
be deemed to be incorporated by reference in this Prospectus and to be part
hereof. Any statement contained herein or in a Prospectus Supplement, or in a
document incorporated or deemed to be incorporated by reference herein or
therein shall be deemed to be modified or superseded for purposes of this
Prospectus and any Prospectus Supplement to the extent that a statement
contained herein or in any other subsequently filed document that also is or is
deemed to be incorporated by reference herein modifies or supersedes such
statement. Any such statement so modified or superseded shall not be deemed,
except as so modified or superseded, to constitute a part of this Prospectus or
any Prospectus Supplement.
The Note Issuer will provide without charge to each person to whom a copy
of this Prospectus is delivered, on the written or oral request of any such
person, a copy of any of or all the documents incorporated herein by reference
(other than exhibits to such documents). Requests for such copies should be
directed to the Note Issuer at Mail Code N4E, P.O. Box 770000, San Francisco, CA
94177 or by telephone at (415) 972-5467.
PROSPECTUS SUPPLEMENT
The Prospectus Supplement for a Series of Certificates will describe the
following terms of such Series and, if applicable, the Classes thereof: (a) the
designation of the Series and, if applicable, the Classes thereof, (b) the
principal amount, (c) the annual rate at which interest accrues or, if the Trust
has entered into a Swap Agreement with respect to such Series, the index on
which a variable rate of interest will be based, (d) the dates on which
distributions of interest and principal will occur, (e) the Scheduled Final
Distribution Date, (f) the Termination Date of the Series, (g) the issuance date
of the Series, (h) the place or places for the payment of principal and
interest, (i) the authorized denominations, (j) the provisions for redemption by
the Trust as a result of an optional redemption by the Note Issuer of the
underlying Notes which will, in no event, be permitted unless the outstanding
principal balance thereof is less than five percent of the initial principal
balance thereof, (k) the Expected Amortization Schedule for principal of such
Series and, if applicable, the Classes thereof, (l) the terms, if any, on which
any Class of Certificates will be subordinated to any other Class of
Certificates, (m) the FTA Charges as of the date of issuance of such Series of
5
<PAGE>
Certificates, and the portion of the FTA Charges attributable to such Series of
Certificates, (n) any other terms of such Series and any Class thereof that are
not inconsistent with the provisions of the Certificates and that will not
result in any Rating Agency reducing or withdrawing its then current rating of
any outstanding Series or Class of Notes or Certificates, (o) the identity of
the Certificate Trustee and the Delaware Trustee and (p) the terms of any
interest rate exchange agreement executed solely to permit the issuance of
variable rate Certificates.
6
<PAGE>
TABLE OF CONTENTS
-----------------
<TABLE>
<CAPTION>
Page
----
<S> <C>
AVAILABLE INFORMATION.............................................. 3
REPORTS TO HOLDERS................................................. 3
INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE.................... 4
PROSPECTUS SUPPLEMENT.............................................. 4
PROSPECTUS SUMMARY................................................. 7
RISK FACTORS....................................................... 23
Unusual Nature of the Transition Property..................... 23
Potential Servicing Issues.................................... 25
Uncertainties Related to the Electric Industry Generally...... 27
Bankruptcy and Creditors' Rights Issues....................... 28
Nature of the Certificates.................................... 30
ENERGY DEREGULATION AND NEW CALIFORNIA MARKET STRUCTURE............ 33
DESCRIPTION OF THE TRANSITION PROPERTY............................. 34
General....................................................... 34
Financing Order and Advice Letters............................ 34
Transition Property........................................... 35
Nonbypassable FTA Charges..................................... 36
Adjustments to the FTA Charges................................ 36
Sale and Assignment of Transition Property.................... 37
Seller Representations and Warranties......................... 38
CERTAIN DISTRIBUTION AND WEIGHTED AVERAGE LIFE CONSIDERATIONS...... 39
THE TRUST.......................................................... 39
THE INFRASTRUCTURE BANK............................................ 40
THE NOTE ISSUER.................................................... 41
Officers...................................................... 41
THE SELLER AND SERVICER............................................ 42
General....................................................... 42
PG&E Customer Base and Electric Energy Consumption............ 42
Forecasting Consumption....................................... 43
Forecast Variance............................................. 43
Credit Policy; Billing; Collections; Restoration of Service... 44
Loss and Delinquency Experience............................... 46
Delinquencies................................................. 47
SERVICING.......................................................... 47
Servicing Procedures.......................................... 47
Servicing Standards and Covenants............................. 48
Remittances to Collection Account............................. 48
No Servicer Advances.......................................... 49
Servicing Compensation........................................ 49
Aggregators and Other Suppliers............................... 49
Servicer Representations and Warranties....................... 49
Statements by Servicer........................................ 50
Evidence as to Compliance..................................... 50
Certain Matters Regarding the Servicer........................ 51
Servicer Defaults............................................. 51
Rights Upon Servicer Default.................................. 52
</TABLE>
7
<PAGE>
<TABLE>
<CAPTION>
Page
----
<S> <C>
Waiver of Past Defaults....................................... 52
Amendment..................................................... 52
Termination................................................... 53
DESCRIPTION OF THE NOTES.......................................... 53
General....................................................... 53
Security...................................................... 53
Interest and Principal........................................ 54
Optional Redemption........................................... 55
Overcollateralization Amount.................................. 55
Other Credit Enhancement...................................... 56
Allocations; Payments......................................... 57
Actions by Noteholders........................................ 58
Note Events of Default; Rights Upon Note Event of Default..... 59
Certain Covenants of the Note Issuer.......................... 60
Reports to Noteholders........................................ 62
Annual Compliance Statement................................... 62
DESCRIPTION OF THE CERTIFICATES.................................... 63
General....................................................... 63
Payments and Distributions.................................... 63
Voting of the Notes........................................... 65
Events of Default............................................. 65
Optional Redemption........................................... 67
Reports to Certificateholders................................. 67
Amendments.................................................... 68
List of Certificateholders.................................... 68
Registration and Transfer of the Certificates................. 69
Book-Entry Registration....................................... 69
Definitive Certificates....................................... 72
Conditions of Issuance of Additional Series................... 73
CERTAIN FEDERAL INCOME TAX CONSEQUENCES............................ 73
General....................................................... 73
Treatment of the Certificates as Debt......................... 74
Taxation of Interest Income of U.S. Certificateholders........ 74
Sale or Exchange of Certificates.............................. 75
Non-U.S. Certificateholders................................... 76
Information Reporting and Backup Withholding.................. 76
STATE TAXATION..................................................... 77
California Taxation........................................... 77
Other States.................................................. 77
ERISA CONSIDERATIONS............................................... 77
USE OF PROCEEDS.................................................... 78
PLAN OF DISTRIBUTION............................................... 78
RATINGS............................................................ 79
LEGAL MATTERS...................................................... 79
INDEX OF PRINCIPAL DEFINITIONS..................................... 80
</TABLE>
8
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9
<PAGE>
PROSPECTUS SUMMARY
The following Prospectus Summary is qualified in its entirety by reference
to the detailed information appearing elsewhere in this Prospectus and by
reference to the information with respect to each Series of Certificates
contained in the related Prospectus Supplement. Capitalized terms used but not
defined in this Prospectus Summary have the meanings ascribed to such terms
elsewhere in this Prospectus. The Index of Principal Definitions which begins
on page ___ sets forth the pages on which the definitions of certain principal
terms appear.
Transaction Overview Assembly Bill 1890, Chapter 854, California Statutes of
1996 (as amended, the "STATUTE"), permits the
California investor-owned utilities (collectively, the
"UTILITIES"), including PG&E, to finance the recovery
of a portion of their respective "Transition Costs"
through the issuance of the Certificates, in
conjunction with a reduction in electricity rates for
Residential Customers and Small Commercial Customers.
Transition Costs consist of the costs of generation-
related assets and obligations that may become
uneconomic as a result of a competitive generation
market, together with certain other costs associated
therewith.
The Seller will sell to the Note Issuer the Transition
Property, which represents the right to receive
payments made in respect of certain nonbypassable
charges included in the regular utility bills of
residential and small commercial consumers located in
the historical service territory of the Seller. These
charges are nonbypassable in that applicable consumers
cannot avoid paying them if they purchase electricity
from a supplier other than the Seller. The Seller will
sell the Transition Property to the Note Issuer in
exchange for the proceeds of the Notes.
The Note Issuer will issue the notes (the "NOTES"),
which will be secured by the Transition Property and
the other Note Collateral described under "Description
of the Notes--Security" herein, and sell the Notes to
the Trust in exchange for the proceeds of the sale of
the Certificates. The Trust is being established by
the Infrastructure Bank. The Trust, whose sole assets
will be the Notes and any interest rate exchange
agreement executed solely to permit the issuance of
variable rate Certificates (a "SWAP AGREEMENT"), will
issue the Certificates, which will be sold to the
underwriters named in each Prospectus Supplement. The
Certificates of each Class represent an undivided
interest in the related Class of Notes, the proceeds
thereof and payments pursuant to any related Swap
Agreement.
The charges represented by the Transition Property are
calculated to be sufficient over time to pay principal
of and interest on the Notes and, in turn, the
Certificates, all related fees and expenses and the
Overcollateralization Amount described herein. These
charges will be subject to adjustment pursuant to the
true-up mechanism described under "Description of the
10
<PAGE>
Transition Property--Adjustments to the FTA Charges"
herein over the term of each Series of Certificates to
enhance the likelihood of timely recovery of such
amounts, although there can be no assurance that the
true-up mechanism will operate as intended or that
principal of and interest on any Series or Class of
Certificates will be paid as scheduled.
Risk Factors Investors should consider the risks associated with an
investment in the Certificates. For a discussion of
certain material risks associated therewith, investors
should review the discussion under "Risk Factors" which
begins at page __.
Seller and Servicer Pacific Gas and Electric Company, a California
corporation ("PG&E"). PG&E will sell the Transition
Property (in its capacity as seller, the "SELLER") to
PG&E Funding LLC, a Delaware limited liability company
of which the Seller is the sole member (the "NOTE
ISSUER"), pursuant to a Transition Property Purchase
and Sale Agreement between the Seller and the Note
Issuer (together with any subsequent sale agreement
relating to Subsequent Transition Property, the "SALE
AGREEMENT").
The Seller will also act as the servicer of the
Transition Property (in its capacity as servicer, the
"SERVICER") pursuant to a Transition Property
Servicing Agreement between the Note Issuer and the
Servicer (the "SERVICING AGREEMENT").
PG&E is a public utility primarily engaged in the
business of supplying electric energy and natural gas
to customers in an approximately 70,000 square-mile
area of Northern and Central California.
See "The Seller and Servicer" herein.
Issuer of Certificates A trust entitled "California Infrastructure and
Economic Development Bank Special Purpose Trust PG&E-1"
(the "TRUST") to be established by the California
Infrastructure and Economic Development Bank (the
"INFRASTRUCTURE BANK"). The Trust will not be an
agency or instrumentality of the State of California.
The Trust will be governed by an amended and restated
Declaration and Agreement of Trust among the
Infrastructure Bank, the Delaware Trustee and the
Certificate Trustee (the "TRUST AGREEMENT"). The
Certificateholders will be the beneficiaries of the
Trust upon the issuance of the Certificates. See "The
Trust" herein.
Infrastructure Bank A public body established within the state government
of the State of California. Under the Statute, the
Infrastructure Bank must approve the issuance of
Certificates by the Trust. However, the Infrastructure
Bank will not guarantee,
11
<PAGE>
insure or otherwise support payments or distributions
on, as applicable, the Certificates, the Notes or the
Transition Property, nor will the Infrastructure Bank
have any other obligations with respect thereto. See
"The Infrastructure Bank" herein.
Certificate Trustee The entity named as co-trustee under the Trust
Agreement, as set forth in each Prospectus Supplement
(the "CERTIFICATE TRUSTEE").
Delaware Trustee The Delaware entity named as co-trustee under the Trust
Agreement, as set forth in each Prospectus Supplement
(the "DELAWARE TRUSTEE").
The Certificates The California Infrastructure and Economic Development
Bank Special Purpose Trust PG&E-1 Rate Reduction
Certificates (the "CERTIFICATES"), issuable in Series.
The Certificates will be issuable under the terms of
the Trust Agreement.
The Certificates may be issued in one or more series
(each, a "SERIES"), and the Certificates of each Series
may be issued in one or more classes (each, a "CLASS").
Each Class of Certificates will correspond to a Class
of Notes and will represent undivided interests in such
underlying Class of Notes, the proceeds thereof and
payments pursuant to any related Swap Agreement.
Accordingly, each Class of Certificates will entitle
the holders thereof to receive the payments received by
the Trust in respect of the corresponding Class of
Notes. The funds received by the Trust from the
payments on each Class of Notes will be the only source
of distributions on the Certificates of the
corresponding Class. Each Note will be secured by all
of the Transition Property owned by the Note Issuer and
the other Note Collateral described under "Description
of the Notes--General" herein. The Certificates are
entitled to all of the benefits accorded to "rate
reduction bonds" by the Statute. The issuance and sale
of any Series or Class of Certificates is contingent
upon the effectiveness of the Financing Order and the
applicable Issuance Advice Letter.
A Series may include two or more Classes of
Certificates which differ as to the interest rate,
timing, sequential order and amount of distributions of
principal or interest or both or otherwise.
While the specific terms of any Series of Certificates
(and the Classes thereof, if any) in respect of which
this Prospectus is being delivered will be described in
the related Prospectus Supplement, the terms of such
Series and any Classes thereof will not be subject to
prior review by, or consent of, the holders of the
Certificates of any previously issued Series.
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<PAGE>
The assets of the Trust will be allocated among the
Certificateholders of each Series of Certificates
issued by the Trust in the manner described herein. If
a Series includes two or more Classes of Certificates,
the assets of the Trust allocable to the Certificates
of such Series will be further allocated among each
Class in such Series in the manner described in the
Prospectus Supplement.
All Certificates of the same Series will be identical
in all respects except for the denominations thereof,
unless such Series is comprised of two or more Classes,
in which case all Certificates of the same Class will
be identical in all respects except for the
denominations thereof.
So long as any Certificates are outstanding, the
Certificateholders will direct the Certificate Trustee,
as sole Noteholder, as to matters in which the
Noteholders are permitted or required to take action;
provided, however, that the Certificate Trustee will be
permitted to take certain actions specified in the
Trust Agreement without the direction of the
Certificateholders. See "Description of the Notes--
Actions by Noteholders" herein.
None of the Certificates, the Notes or the underlying
Transition Property will be guaranteed or insured by
any governmental agency or instrumentality or by the
Seller or any of its affiliates. Neither the full
faith and credit nor the taxing power of the State of
California is pledged to the payment of principal of or
interest on the Certificates or the Notes or to the
payments in respect of the Transition Property.
See "Description of the Certificates" and "Description
of the Notes" herein.
Note Issuer PG&E Funding LLC, a Delaware special purpose limited
liability company whose single member is PG&E. The
assets of the Note Issuer will consist of the
Transition Property and the other Note Collateral,
including capital contributed by PG&E in an amount
specified in each Prospectus Supplement, which will
equal 0.50% of the initial principal amount of all
Notes issued and outstanding pursuant to the Indenture.
The principal executive office of the Note Issuer is
located at 245 Market Street, Room 424, San Francisco,
California 94105, and its telephone number is (415)
972-5467.
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<PAGE>
The Notes The Notes of each Series and Class issued by the Note
Issuer will be in an initial aggregate principal amount
equal to the initial aggregate principal amount of the
related Series and Class of Certificates, and the Notes
of each Series and Class will bear interest at an
interest rate equal to the interest rate of the related
Series and Class of Certificates, unless a Swap
Agreement is entered into in connection with the
issuance of any Series or Class of Certificates, as
described in the related Prospectus Supplement.
The Note Issuer will use all collections received with
respect to the Transition Property (FTA Collections, as
more specifically defined below) to pay fees payable to
the Note Trustee, the Certificate Trustee, the Delaware
Trustee, the Servicer and the Administrator, other
Operating Expenses, interest due on the Notes and
principal payable on the Notes, allocated among the
Series and Classes of Notes based on the priorities
described herein and in the Prospectus Supplement,
until each outstanding Series and Class of Notes is
retired. However, as described under "Description of
the Notes--Interest and Principal" herein, principal of
any Series or Class of Notes on any Payment Date will
only be paid until the outstanding principal balance of
such Series or Class has been reduced to the principal
balance specified in the applicable Expected
Amortization Schedule for such Distribution Date. Any
FTA Collections remaining with respect to such
Distribution Date will be allocated to the various
subaccounts of the Collection Account, as described
below. All principal not previously paid, if any, on a
Note is due and payable on the Final Maturity Date of
such Note, which will correspond with the Termination
Date of the related Class of Certificates.
Each Series of Notes represents a non-recourse
obligation of the Note Issuer, and will be secured only
by Transition Property owned by the Note Issuer,
together with the other Note Collateral.
See "Description of the Notes" herein.
Note Trustee The entity named as trustee under the Note Indenture,
as set forth in each Prospectus Supplement (the "NOTE
TRUSTEE").
Transition Costs In connection with the restructuring of the electric
utility industry in California to facilitate increased
competition among providers of electricity, Sections
367 and 369 of the California Public Utilities Code
(the "PU CODE") provide the Seller, as well as the
other Utilities providing electricity to consumers in
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<PAGE>
California, with an opportunity to recover certain
costs. These costs, commonly known as stranded costs
and referred to herein and in the Statute as
"TRANSITION COSTS," consist of the costs of generation-
related assets and obligations that may become
uneconomic as a result of a competitive generation
market, together with certain other costs associated
therewith. Examples of generation-related assets
include generation facilities, generation-related
regulatory assets, amounts recoverable in electric
rates pursuant to settlement agreements with the
California Public Utilities Commission (the "CPUC") in
connection with nuclear power plants, power purchase
contracts with third-party generators of electricity
(including voluntary restructuring, renegotiations or
terminations thereof). These assets may become
uneconomic in a competitive generation market, since
they are obligations that were undertaken either
pursuant to legal requirements or with the
understanding that they would be recoverable in rates
approved by the CPUC. Since other participants in a
competitive market, unburdened by these uneconomic
assets, may be able to offer electricity at lower
rates, the costs relating to these uneconomic assets
may not be recoverable in a competitive market.
FTA Charges Under Section 840 of the PU Code, the Seller has
obtained from the CPUC a Financing Order (the
"FINANCING ORDER") designating the amount of the
Seller's Transition Costs to be financed, along with
the costs of providing, recovering, financing or
refinancing the Transition Costs, including the costs
of issuing, servicing and retiring the Certificates.
The total amount specified in the Financing Order which
may be financed, including associated costs, is
$3,500,000,000. In order to enable the Seller to
recover the Transition Costs and associated costs, the
CPUC has authorized, in the Financing Order, the
establishment of nonbypassable, usage-based, per
kilowatt hour charges on designated consumers of
electricity (the "FTA CHARGES"). The FTA Charges will
be payable by existing and future Residential Customers
and Small Commercial Customers (each, as defined below
and collectively, the "CUSTOMERS") of electricity in
the territory of the Seller specified by the Statute.
The territory specified by the Statute is the territory
in which the Seller provided electricity services as of
December 20, 1995 (the "TERRITORY"). The two defined
classes of consumers comprising the Customers are (i)
residential consumers (the "RESIDENTIAL CUSTOMERS") and
(ii) small commercial consumers, which are defined as
all commercial consumers who do not have demand meters,
other commercial consumers whose peak demand,
determined on a one-time basis, was less than 20
kilowatts in at least nine of the twelve billing
periods prior to
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October 1, 1997, and new commercial customers since
that time whose peak demand, estimated on a one-time
basis, is less than 20 kilowatts ("SMALL COMMERCIAL
CUSTOMERS"). Because of differences in the tariff rate
for each class of Customers, the FTA Charge payable by
Residential Customers is expected to be different from
the FTA Charge payable by Small Commercial Customers;
the initial FTA Charges will result in FTA Payments by
the Residential Customers and Small Commercial
Customers representing approximately __% and __%,
respectively, of the aggregate FTA Payments. The
foregoing percentages may change from time to time
based on fluctuations in Customer composition.
The FTA Charges will be calculated and adjusted from
time to time to generate projected revenues sufficient
to provide for the amortization of each Series of
Certificates in accordance with the related Expected
Amortization Schedule, together with the
Overcollateralization Amount described herein and fees
and expenses related to the issuance and servicing of
the Certificates. The FTA Charges are, specifically,
separate charges that will be assessed on (i) the class
of electricity consumers comprised of Residential
Customers and (ii) the class of electricity consumers
comprised of Small Commercial Customers. In each case,
the FTA Charge will be assessed for the benefit of the
Note Issuer as owner of the Transition Property based
on the applicable Customer's actual consumption of
electricity. Such amounts will be collected by the
Servicer as part of its normal collection activities
and will be deposited into the Collection Account under
the terms of the Note Indenture on each Remittance Date
(as defined below).
The Financing Order requires a notification letter
(each, an "ISSUANCE ADVICE LETTER") to be submitted to
the CPUC prior to the issuance of each Series of
Certificates. The first Issuance Advice Letter will
establish the initial FTA Charges, calculated using the
Base Calculation Model which is described under
"Description of the Transition Property--Financing
Order and Advice Letters" herein. Subsequent Issuance
Advice Letters may modify the FTA Charges to support
the issuance of additional Series of Certificates. The
Issuance Advice Letters and the True-Up Mechanism
Advice Letters (as defined below) are collectively
referred to as "ADVICE LETTERS." The Servicing
Agreement requires the Servicer to calculate
adjustments to the FTA Charges and to file True-Up
Mechanism Advice Letters from time to time as needed.
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<PAGE>
Transition Property The right to collect payments based on the FTA Charges
from the Customers (such payments being the "FTA
PAYMENTS") gives rise to a separate property right
under California law and is referred to herein
generally as the "TRANSITION PROPERTY." FTA Payments
received by the Servicer and remitted to the Collection
Account are referred to generally herein as the "FTA
COLLECTIONS." " Transition Property" is defined more
specifically in Section 840(g) of the PU Code as the
property right created under the PU Code including,
without limitation, the right, title and interest of an
electrical corporation or its transferee (i) in and to
the FTA Charges, as adjusted from time to time, (ii) to
be paid the FTA Payments, and (iii) to obtain
adjustments to the FTA Charges, as provided in the PU
Code.
Adjustments to
FTA Charges In order to enhance the likelihood that the actual FTA
Collections are neither more nor less than the amount
necessary to amortize the Certificates in accordance
with the Expected Amortization Schedules and fund the
Overcollateralization Subaccount, the Servicing
Agreement requires the Servicer to seek, and the
Statute and the Financing Order require the CPUC to
approve, periodic adjustments to the FTA Charges based
on actual FTA Collections and updated assumptions by
the Servicer as to projected future usage of
electricity by Customers, future expenses relating to
the Transition Property, the Notes and the
Certificates, and expected delinquencies and charge-
offs. Each Advice Letter relating to an adjustment to
the FTA Charge is referred to as a "TRUE-UP MECHANISM
ADVICE LETTER." The adjustments to the FTA Charges will
continue until all interest on and principal of all
Series of Notes and corresponding Series of
Certificates have been paid or distributed in full.
The Servicer will file a routine True-Up Mechanism
Advice Letter annually, requesting modifications to the
FTA Charges. Calculations of appropriate modifications
to the FTA Charges will be made based on the True-Up
Mechanism Calculation Model, which is described under
"Description of the Transition Property--Adjustments to
the FTA Charges" herein. The Servicer will also file a
routine True-Up Mechanism Advice Letter quarterly, if
the amount of FTA Payments causes the aggregate
outstanding principal balance of the Certificates to
vary from the Expected Amortization Schedule for all
outstanding Certificates as of any Distribution Date by
more than an amount to be
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<PAGE>
specified in each Prospectus Supplement or if amounts
on deposit in the Collection Account vary from amounts
specified in each Prospectus Supplement. The Servicer
may also file a non-routine True-Up Mechanism Advice
Letter as often as quarterly, to revise the Base
Calculation Model or True-Up Mechanism Calculation
Model, if either of such models no longer accurately
forecasts required collections. True-Up Mechanism
Advice Letters will take into account amounts available
in the General Subaccount and Reserve Subaccount, and
amounts necessary to replenish the
Overcollateralization Subaccount and Capital Subaccount
to required levels, in addition to amounts payable on
the Notes.
See "Description of the Transition Property--
Adjustments to the FTA Charges" herein.
State Pledge Pursuant to Section 841(c) of the PU Code, the
Infrastructure Bank, on behalf of the State of
California, pledges and agrees with the Trust and the
Holders of the Certificates that the State of
California shall neither limit nor alter the FTA
Charges, the Transition Property, or the Financing
Order or Advice Letters relating thereto, or any rights
thereunder, until the Certificates, together with
interest thereon, are fully paid and discharged,
provided nothing contained in this pledge and agreement
shall preclude such limitation or alteration if and
when adequate provision shall be made by law for the
protection of the Holders (the "STATE PLEDGE").
Customers The Customers consist of Residential Customers and
Small Commercial Consumers in the Territory. The sole
source of payments on the Certificates will be payments
on the Notes and payments pursuant to any related Swap
Agreement; the sole sources of payments on the Notes
will be FTA Charges collected from the Customers and
amounts available or realized from the other Note
Collateral (which is not expected to be substantial).
Of amounts collected from the Customers, only the
portion of amounts collected attributable to the FTA
Charges, as adjusted from time to time, will be
available for distributions on the Certificates.
Distribution and
Payment Dates Unless otherwise specified in the related Prospectus
Supplement, each March 25, June 25, September 25 and
December 25 (or, if any such date is not a Certificate
Business Day, the next succeeding Certificate Business
Day) following the Closing Date for a Series of
Certificates, the quarterly dates on which
distributions will be made to specified holders of
Certificates of such Series (each, a "DISTRIBUTION
DATE"). Each Distribution
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Date with respect to the Certificates will also be a
date on which payments are made with respect to the
Notes (each, a "PAYMENT DATE").
Record Dates With respect to any Distribution Date, the last day of
the preceding calendar month (each, a "RECORD DATE").
Final Distribution and
Termination Dates For each Class of Certificates, the related Prospectus
Supplement will specify a Scheduled Final Distribution
Date and a Termination Date. The "SCHEDULED FINAL
DISTRIBUTION DATE" will be the date when all principal
of and interest on the related Class of Certificates is
expected to be distributed in full, based on various
assumptions described herein. Failure to pay principal
of and interest on any Class of Certificates in full by
the "TERMINATION DATE," which will be a date specified
in the related Prospectus Supplement after the related
Scheduled Final Distribution Date, shall constitute an
Event of Default and the Certificate Trustee may, and
upon the written direction of the holders of not less
than a majority in principal amount of all Certificates
of all Series then outstanding shall, declare the
unpaid principal amount of all the Notes of all Series
then outstanding to be due and payable. The Scheduled
Final Distribution Date and the Termination Date for
any Class of Certificates will coincide with the
Scheduled Maturity Date and Final Maturity Date,
respectively, for the related Class of Notes. See
"Description of the Certificates--Events of Default"
and "Ratings" herein.
Issuance of New Series The Trust is authorized to issue new Series of
Certificates from time to time. See "Description of
the Transition Property--Financing Order and Advice
Letters." A new Series may be issued only upon
satisfaction of the conditions described under
"Description of the Certificates--Conditions of
Issuance of Additional Series" herein. Each Series of
Certificates will represent an interest in payments to
be made on a Series of Notes, which in turn will be
secured by the Transition Property and the other Note
Collateral. Because the Transition Property will
secure each Series or Class of Notes ratably, a
Certificate Event of Default with respect to one Series
of Certificates (or one or more Classes thereof) may
adversely affect other outstanding Classes or Series of
Certificates.
Interest Unless otherwise specified in the related Prospectus
Supplement, interest on each Class of Certificates will
accrue and be distributable in arrears at the interest
rate for such Class specified in the related Prospectus
Supplement. Interest accrued on each Class of
Certificates at the applicable interest rate will be
distributed, to the extent monies are available
therefor, on each Distribution Date, commencing on the
day specified in the related Prospectus Supplement and
will be distributed in the manner specified
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<PAGE>
in such Prospectus Supplement, to the extent of
payments received with respect to the related Class of
Notes or any related Swap Agreement on the Payment Date
for the Notes occurring on the same day as such
Distribution Date. Note Events of Default will include
failure to make any payment of interest within five
days after the Payment Date on which such payment is
due.
Principal Principal of each Class of Certificates will be
distributed to the Certificateholders of such Class in
the amounts and on the Distribution Dates specified in
the related Prospectus Supplement, but only to the
extent that amounts in the Collection Account are
available therefor, and subject to the other
limitations described below. See "Description of the
Notes--Allocations; Payments" and "Description of the
Certificates--Payments and Distributions" herein. The
related Prospectus Supplement will set forth a schedule
of the expected amortization of principal of the
related Series of Certificates and, if applicable, the
Classes thereof (for any Series or Class, the "EXPECTED
AMORTIZATION SCHEDULE"). On any Payment Date, the Note
Issuer will make principal payments on the Notes only
until the outstanding principal balances thereof have
been reduced to the principal balances specified in the
applicable Expected Amortization Schedules for such
Payment Date; accordingly, on the related Distribution
Date, the Trust similarly will only make principal
distributions on the Certificates in such amounts. Any
FTA Collections in excess of amounts payable as (a)
expenses of the Note Issuer and the Trust, (b) payments
of interest on and principal of the Notes, (c)
allocations to the Overcollateralization Subaccount and
(d) allocations to the Capital Subaccount (all as
described herein under "Description of the Notes--
Allocations; Payments" herein) will be retained by the
Note Trustee in the Reserve Subaccount for payment on
subsequent Payment Dates. However, if insufficient FTA
Collections are received with respect to any Payment
Date, and amounts in the Collection Account are not
sufficient to make up the shortfall, principal of any
Series or Class of Certificates may be distributed
later than reflected in the related Expected
Amortization Schedule, as described herein and in the
related Prospectus Supplement. See "Risk Factors--
Uncertain Distribution Amounts and Weighted Average
Life" and "Certain Distribution and Weighted Average
Life Considerations" herein.
If an event of default under the Trust Agreement, other
than a breach of the State Pledge by the State of
California, has occurred and is continuing with respect
to any Series or Class of Certificates, the Certificate
Trustee may and,
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<PAGE>
upon the written direction of the holders of a majority
in principal amount of all Series of Certificates then
outstanding shall declare the unpaid principal amount
of all the Notes of all Series then outstanding to be
due and payable. A Certificate Event of Default is
defined as the occurrence and continuance of an Event
of Default under the Notes (a "NOTE EVENT OF DEFAULT")
or a breach by the State of California of the State
Pledge (collectively, a "CERTIFICATE EVENT OF DEFAULT"
and, together with a Note Event of Default, an "EVENT
OF DEFAULT"). See "Description of the Certificates--
Events of Default" herein.
Optional Redemption The Note Issuer may redeem any Series of Notes relating
to a Series of Certificates, and accordingly cause the
Trust to redeem the related Series of Certificates, if
the outstanding principal balance of such Series of
Notes has been reduced to less than five percent of the
initial principal balance thereof. See "Description of
the Certificates--Optional Redemption" herein.
Collection Account
and Subaccounts Upon issuance of the initial Series of Notes, the Note
Issuer will establish the Collection Account, which
will be held by the Note Trustee for the benefit of the
Noteholders. The Collection Account will consist of
four subaccounts: a general subaccount (the "GENERAL
SUBACCOUNT"), a reserve subaccount (the "RESERVE
SUBACCOUNT"), a subaccount for the Over-
collateralization Amount (the "OVERCOLLATERALIZATION
SUBACCOUNT") and a capital subaccount (the "CAPITAL
SUBACCOUNT"). Unless the context indicates otherwise,
references herein to the Collection Account include
each of the subaccounts contained therein. Withdrawals
from and deposits to these subaccounts will be made as
described under "Description of the Notes--Allocations;
Payments" herein.
Overcollateralization In order to enhance the likelihood that distributions
on each Series of the Certificates will be made in
accordance with their Expected Amortization Schedules,
the Financing Order permits the Servicer to set the FTA
Charges at levels that are expected to produce FTA
Collections in amounts that exceed the amounts expected
to be required to make all distributions on the related
Series of Certificates in a timely manner and to pay
all related fees and expenses. The amount of such
excess will be specified in the related Prospectus
Supplement. Any such excess amount will be held in the
Overcollateralization Subaccount, as described further
under "Description of the Notes--Overcollateralization
Amount" herein, and will be available to pay any
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<PAGE>
periodic shortfalls in amounts available for scheduled
payments on the Notes.
Capital Subaccount Upon the issuance of each Series of Notes, the Seller
will contribute capital to the Note Issuer in an amount
specified in each Prospectus Supplement, which will
equal 0.50% of the initial principal amount of each
such Series of Notes. Such amount, less $100,000 in
the aggregate for all Series of Notes (with respect to
each Series, the "REQUIRED CAPITAL LEVEL"), will be
deposited into the Capital Subaccount. Withdrawals
from and deposits to the Capital Subaccount will be
made as described under "Description of the Notes--
Allocations; Payments" herein.
Reserve Subaccount FTA Collections available with respect to any Payment
Date in excess of amounts payable as (a) expenses of
the Note Issuer and the Trust, (b) payments of
principal of and interest on the Notes, (c) allocations
to the Overcollateralization Subaccount and (d)
allocations to the Capital Subaccount (all as described
under "Description of the Notes--Allocations; Payments"
herein), will be allocated to the Reserve Subaccount.
On each Payment Date, the Note Trustee will draw on
amounts in the Reserve Subaccount, to the extent
amounts available in the General Subaccount are
insufficient to make scheduled payments on the Notes.
Other Credit Enhancement Although the true-up adjustment mechanism and amounts
available in the Reserve Subaccount, the
Overcollateralization Subaccount and the Capital
Subaccount are expected to provide sufficient credit
enhancement for the Notes, other types of credit
enhancement may be provided with respect to one or more
Series or Classes of Notes, as specified in the related
Prospectus Supplement. See "Description of the Notes--
Other Credit Enhancement" herein.
Collections; Allocations;
Distributions Except as otherwise specified herein, on the twentieth
calendar day of each calendar month (or, if such day is
not a Certificate Business Day, the following
Certificate Business Day), the Servicer will remit to
the Collection Account FTA Payments expected to have
been received during the preceding calendar month (the
"BILLING PERIOD"). Because of billing system
limitations, the amounts remitted will be based on the
Collections Curve, increased
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<PAGE>
or reduced as described herein under "Servicing--
Remittances to Collection Account."
On each Payment Date, amounts in the Collection
Account, including net earnings thereon (subject to the
priority of withdrawals described in the following
paragraph), will be allocated to the following (in the
priority indicated): (1) all amounts owed by the Note
Issuer or the Trust to the Note Trustee, the Delaware
Trustee and the Certificate Trustee will be paid to
such persons; (2) the Servicing Fee and all unpaid
Servicing Fees from prior Billing Periods will be paid
to the Servicer; (3) the Quarterly Administration Fee
payable under the Administrative Services Agreement
between the Note Issuer and PG&E, as administrator (the
"ADMINISTRATOR"), and all unpaid Quarterly
Administration Fees from prior Payment Dates will be
paid to the Administrator; (4) so long as no Event of
Default has occurred or would be caused by such
payment, all other fees, costs, expenses and
indemnities of the Note Issuer and the Trust
("OPERATING EXPENSES") will be paid to the persons
entitled thereto; (5) Quarterly Interest and any
overdue Quarterly Interest with respect to each Series
of Notes will be transferred to the Certificate
Trustee, as Noteholder, for distribution to the
Certificateholders; (6) principal on any Series of
Notes payable as a result of a Note Event of Default or
on the Final Maturity Date for such Series of Notes
will be transferred to the Certificate Trustee, as
Noteholder, for distribution to the Certificateholders;
(7) funds necessary to pay Quarterly Principal for any
Series of Notes based on priorities described in each
Prospectus Supplement will be transferred to the
Certificate Trustee, as Noteholder, for distribution to
the applicable Certificateholders; (8) unpaid Operating
Expenses will be paid to the persons entitled thereto;
(9) an amount up to the sum of the Quarterly
Overcollateralization Collection and any unfunded
Quarterly Overcollateralization Collections from prior
Payment Dates will be allocated to the
Overcollateralization Subaccount; (10) an amount up to
the excess of the Required Capital Level with respect
to all outstanding Series of Notes
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<PAGE>
over the amount in the Capital Subaccount as of such
Payment Date will be allocated to the Capital
Subaccount; (11) funds up to the net earnings on
amounts in the Collection Account for the prior quarter
without cumulation will be released to the Note Issuer;
(12) if any Series of Notes has been retired as of such
Payment Date, the excess of the amount in the
Overcollateralization Subaccount over the aggregate
Overcollateralization Amount with respect to all Series
of Notes remaining outstanding will be released to the
Note Issuer; (13) if any Series of Notes has been
retired as of such Payment Date, the excess of the
amount in the Capital Subaccount over the aggregate
Required Capital Level with respect to all Series of
Notes remaining outstanding will be released to the
Note Issuer; (14) the balance, if any, will be
allocated to the Reserve Subaccount for distribution on
subsequent Payment Dates; and (15) following the
repayment of all outstanding Series of Notes, the
balance, if any, will be released to the Note Issuer.
If on any Payment Date funds on deposit in the General
Subaccount are insufficient to make the transfers
contemplated by clauses (1) through (7) above, the Note
Trustee will (i) first, draw from amounts on deposit in
the Reserve Subaccount, (ii) second, draw from amounts
on deposit in the Overcollateralization Subaccount, and
(iii) third, draw on amounts on deposit in the Capital
Subaccount, up to the amount of such shortfall, in
order to make the transfers described above. See
"Description of the Notes--Allocations; Payments"
herein.
Servicing The Servicer is responsible for servicing, managing and
receiving FTA Payments in the same manner that it
services and administers bill collections for its own
account. On each Remittance Date, the Servicer will
remit FTA Payments expected to have been received
during the preceding Billing Period (or, if Remittance
Dates are more frequent, for the period since the
preceding Remittance Date). Because of billing system
limitations, the amounts remitted will be based on the
Collections Curve, increased or reduced as described
under "Servicing--Remittances to Collection Account"
herein. Subject to certain conditions described
herein, pending deposit into the Collection Account,
actual FTA Payments received by the Servicer may be
invested by the Servicer at its own risk and for its
own benefit, and will not be segregated from other
funds of the Servicer. See
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<PAGE>
"Servicing--Remittances to Collection Account" herein.
Servicing Compensation The Servicer will be entitled to receive a Servicing
Fee for each calendar quarter in an amount equal to
one-fourth of the percent per annum specified in the
related Prospectus Supplement of the then outstanding
principal amount of the Notes (the "SERVICING FEE").
The Servicing Fee will be paid prior to the
distribution of any amounts in respect of interest on
and principal of the Notes. The Servicer will be
entitled to retain as additional compensation net
investment income on FTA Payments received by the
Servicer prior to remittance thereof to the Collection
Account and the portion of late fees, if any, paid by
Customers relating to the FTA Payments. See
"Servicing--Servicing Compensation" herein.
No Servicer Advances The Servicer will not make any advances of interest or
principal on the Notes.
Denominations Each Class of Certificates will be issued in the
minimum initial denominations set forth in the related
Prospectus Supplement and in integral multiples
thereof.
Registration of the
Certificates Each Class of Certificates may be issued in definitive
form or initially may be represented by one or more
certificates registered in the name of Cede & Co.
("CEDE") ("BOOK-ENTRY CERTIFICATES"), the nominee of
The Depository Trust Company ("DTC"), and available
only in the form of book-entries on the records of DTC,
participating members thereof ("PARTICIPANTS") and
other entities, such as banks, brokers, dealers and
trust companies, that clear through or maintain
custodial relationships with a Participant, either
directly or indirectly ("INDIRECT PARTICIPANTS"). If
so indicated in the applicable Prospectus Supplement,
Certificateholders may also hold Book-Entry
Certificates of a Series through CEDEL or Euroclear (in
Europe), if they are participants in such systems or
indirectly through organizations that are participants
in such systems. Certificates representing Book-Entry
Certificates will be issued in definitive form only
under the limited circumstances described herein and in
the related Prospectus Supplement. With respect to the
Book-Entry Certificates, all references herein to
"HOLDERS" reflect the rights of owners of the Book-
Entry Certificates as they may indirectly exercise such
rights through DTC and Participants, except as
otherwise specified herein. See "Risk Factors" and
"Description of the Certificates--Book-Entry
Registration" herein.
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<PAGE>
Ratings It is a condition of issuance of each Class of
Certificates that at the time of issuance such Class
receive the rating indicated in the related Prospectus
Supplement, which will be in one of the four highest
categories, from one or more nationally recognized
statistical rating agencies (each, a "RATING AGENCY")
specified therein. Each Class of Notes will receive
the same rating from the applicable Rating Agencies as
the corresponding Class of Certificates. See "Ratings"
in the related Prospectus Supplement.
A security rating is not a recommendation to buy, sell
or hold securities and may be subject to revision or
withdrawal at any time. No person is obligated to
maintain any rating on any Certificate and,
accordingly, there can be no assurance that the ratings
assigned to any Class of Certificates upon initial
issuance thereof will not be revised or withdrawn by a
Rating Agency at any time thereafter. If a rating of
any Class of Certificates is revised or withdrawn, the
liquidity of such Class of Certificates may be
adversely affected. In general, the ratings address
credit risk and do not represent any assessment of the
rate of FTA Collections. See "Risk Factors--"Uncertain
Distribution Amounts and Weighted Average Life,"
"Certain Distribution and Weighted Average Life
Considerations" and "Ratings" herein.
Tax Status of the
Certificates The Certificates will be treated as representing
ownership interests in debt for federal income tax
purposes. Interest and original issue discount, if
any, on the Certificates generally will be included in
gross income for federal income tax purposes. See
"Certain Federal Income Tax Consequences" herein and in
the related Prospectus Supplement.
Interest and original issue discount, if any, on the
Certificates will be exempt from California personal
income tax, but not exempt from the California
franchise tax applicable to banks and corporations.
See "State Taxation" herein.
ERISA Considerations A fiduciary of any employee benefit plan or other plan
or arrangement that is subject to the Employee
Retirement Income Security Act of 1974, as amended
("ERISA"), or Section 4975 of the Internal Revenue Code
of 1986, as amended (the "CODE"), should carefully
review with its legal advisors whether the purchase or
holding of the Certificates of any Class or Series
could give rise to a transaction prohibited or not
otherwise permissible under ERISA or the Code. See
"ERISA Considerations" herein and in the related
Prospectus Supplement.
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<PAGE>
RISK FACTORS
Investors should consider, among other things, the following factors in
connection with the purchase of Certificates:
UNUSUAL NATURE OF THE TRANSITION PROPERTY
RELIANCE ON FTA ADJUSTMENTS
The Servicer will be obligated to submit True-Up Mechanism Advice
Letters to the CPUC at least annually and as often as quarterly, seeking
adjustments to the FTA Charges to reflect amounts available in the General
Subaccount and Reserve Subaccount and amounts required to replenish the
Overcollateralization Subaccount and Capital Subaccount to required levels, as
well as the actual rate of FTA Collections, which will vary from projections
upon which the FTA Charges were based, primarily as a result of variations from
projected electricity usage by Customers and expected delinquencies and charge-
offs. PU Code Section 841(c) requires the CPUC to approve adjustments requested
by True-Up Mechanism Advice Letters necessary to assure timely recovery of
Transition Costs, including interest on and principal in accordance with the
related Expected Amortization Schedule of, and the costs of issuance of, the
Certificates. Despite the Statute and the Financing Order, there can be no
assurance that the CPUC will approve such requests in a timely manner. Any
delay in adjustments to the FTA Charges, and any litigation that might ensue as
a consenquence, might adversely affect the price and liquidity of the
Certificates and the dates of maturity thereof, and, accordingly, the weighted
average lives thereof.
POSSIBLE STATE AMENDMENT OR REPEAL OF THE STATUTE
Under the Statute, the State of California pledged and agreed with the
owners of Transition Property and the holders of the Certificates, and the
Infrastructure Bank as agent for the State of California will pledge and
undertake in the Trust Agreement for the benefit of Certificateholders, that the
State will neither limit nor alter the fixed transition amounts, transition
property, financing orders and all rights thereunder until all obligations under
the Certificates are fully met and discharged, provided nothing contained in the
Statute or the Trust Agreement precludes such limitation or alteration by the
State if and when adequate provision shall be made by law for the protection of
the Certificateholders. It is unclear what "adequate provision" would be
afforded to Certificateholders by the State if such limitation or alteration
were attempted. Accordingly, no assurance can be given that any such provisions
would not adversely affect the price of the Certificates, or the timing of
payments with respect to the Certificates.
Under California law, the electorate has the right, through its
initiative powers, to propose statutes as well as amendments to the California
Constitution. Generally, any matter that is a proper subject of legislation can
become the subject of an initiative. Among other procedural requirements, in
order for an initiative measure to qualify for an election, the initiative
measure must be submitted to the State Attorney General and a petition signed by
electors constituting five percent , in the case of a statutory initiative, and
eight percent, in the case of a constitutional initiative, of the votes cast at
the last gubernatorial election must be submitted to the Secretary of State. To
become effective, the initiative must then be approved by a majority vote of the
electors voting at the next general election.
Consumer advocacy groups have publicly announced their opposition to
certain elements of the restructuring plan embodied in the Statute, including
the ability of the Utilities to recover fully their stranded costs and the
issuance of the Certificates. These opponents have indicated their intent to
commence litigation to prevent the sale of the Certificates. In addition,
opponents have announced their intention to draft a ballot initiative to
eliminate the
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Utilities' ability to recover fully stranded costs, including the cost of
nuclear plants. To date no such initiative measure has been submitted to the
State Attorney General, the first step in commencing the initiative
qualification process.
In the opinion of Brown & Wood LLP, counsel to the Trust ("SPECIAL
COUNSEL"), under applicable United States and State of California Constitutional
principles relating to the impairment of contracts, the State of California
could not repeal or amend the Statute (by way of either legislative process or
California voter initiative) or take, or refuse to take, any action required by
the State of California under its pledge and agreement with the
Certificateholders (described above) if such action or inaction would
substantially impair the rights of the Certificateholders, unless such action or
inaction would constitute a reasonable and necessary exercise of the State's
sovereign powers. There have been numerous cases in which legislative or
popular concerns with the burden of taxation or governmental charges have led to
adoption of legislation reducing or eliminating taxes or charges which supported
bonds or other contractual obligations entered into by public instrumentalities.
However, such concerns have not been considered by the courts to provide
sufficient justification for a substantial impairment of the security for such
bonds or obligations provided by the taxes or governmental charges involved.
Based upon such analogous case law (which, however, does not address these
particular circumstances directly), it would appear unlikely that the State
could reduce, modify or alter the Transition Property, or take, or refuse to
take, any action with respect to the Transition Property in a manner which would
substantially impair the rights of the Note Issuer, as owner of Transition
Property, or of Certificateholders. Nonetheless, no assurance can be given that
a repeal of or amendment to the Statute will not be sought or adopted or that
any action, or refusal to act, by the State may not occur, any of which might
constitute a violation of the State's pledge and undertaking with the
Certificateholders. In any such event, costly and time consuming litigation
might ensue. Any such litigation might adversely affect the price and liquidity
of the Certificates and the dates of maturity thereof, and, accordingly, the
weighted average lives thereof. Moreover, given the lack of judicial precedent
directly on point, and the novelty of the security for the Certificates, the
outcome of any such litigation cannot be predicted with certainty and,
accordingly, Certificateholders may fail to receive distributions of principal
and interest.
Furthermore, Section 3 of Article XIIIC of the California Constitution
("PROPOSITION 218") provides that the initiative process shall not be prohibited
or otherwise limited in matters of reducing or repealing any "local" tax,
assessment, fee or charge. There is no controlling precedent interpreting
Proposition 218, given its recent adoption. However, in the opinion of Special
Counsel, the FTA Charges are not a "local" tax, assessment fee or charge to
which Proposition 218 applies, and the initiative power described in Proposition
218 is therefore inapplicable to the FTA Charges, the Transition Property, the
Notes and the Certificates.
POSSIBLE FEDERAL PREEMPTION OF THE STATUTE
At least one bill was introduced in the 105th Congress, First Session,
prohibiting the recovery of stranded costs such as the Transition Costs, which
could negate the existence of the Transition Property that is the source of
payments on the Notes and the Certificates. The bill is H.R. 1230 (The
Consumers Electric Power Act of 1997) ("H.R. 1230"), which was introduced on
April 8, 1997, and has been referred to the House Commerce Committee, where no
further action has been taken. However, the entire California delegation is on
record opposing any federal bill that does not grandfather the provisions of the
Statute. No prediction can be made as to whether H.R. 1230, or any future
proposed bill which would prohibit the recovery of stranded costs, will become
law or, if it becomes law, what its final form or effect will be. See "Energy
Deregulation and the New California Market Structure" herein.
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POSSIBLE LEGAL CHALLENGES
The existence of the Transition Property and its adequacy as a source
of distributions on the Certificates are dependent on relevant provisions of the
PU Code, the Financing Order and applicable Advice Letters. If the relevant
provisions of the PU Code, the Financing Order or any such Advice Letters were
challenged in a lawsuit and determined to be invalid or unenforceable in whole
or in part, such determination could adversely affect the ability of the Note
Issuer to make timely payments on the Notes, and the Certificateholders could
suffer a loss on their investment.
UNCERTAINTIES ASSOCIATED WITH NEW ASSET TYPE
There are no historical performance data for an asset type such as the
Transition Property, although energy usage records are available. Furthermore,
the Servicer does not have any experience administering this specific type of
regulatory asset. See "--Servicing" herein. In addition, in the event of a
foreclosure, there is likely to be a limited market, if any, for the Transition
Property.
POTENTIAL SERVICING ISSUES
RELIANCE ON SERVICER
The Trust relies on the Servicer for the determination of any
adjustments to the FTA Charges and for the Customer billing and collection that
is necessary to recover the FTA Payments and, therefore, necessary to make
distributions on the Certificates. If, as a result of its insolvency or
liquidation or otherwise, PG&E were to cease servicing the Transition Property,
determining any adjustments to the FTA Charges or collecting FTA Payments, it
may be difficult to find a substitute Servicer. In such an event, the timing of
recovery of payment on the Transition Property could be delayed. See
"Servicing" herein.
INACCURATE USAGE AND CREDIT PROJECTIONS
The ability of the Servicer to forecast accurately the electricity
usage of Customers and the delinquency and charge-off experience relating to FTA
Payments will affect significantly whether Certificateholders will receive
timely distributions on the Certificates. Actual energy usage may differ from
projections as a result of weather during the relevant period that is warmer or
cooler than expected. In addition, actual energy usage, delinquencies and
charge-offs may differ from projections as a result of general economic
conditions, trends in demographics that are not precisely as predicted,
unexpected catastrophes, and other causes. During the past five years, the
Servicer's forecasts for energy consumption have been quite accurate, with an
average of a 0.12% underestimate of usage for Residential Customers and an
average of a 5.18% overestimate of usage for small light and power customers
(which are comprised primarily of Small Commercial Customers). (The Servicer
has not historically tracked certain data relating to Small Commercial Customers
as a separate class of consumers.) See "The Seller and Servicer--Forecast
Variance" herein. The accuracy of the Servicer's historical forecasts are not
necessarily indicative of the accuracy of the Servicer's future forecasts and
there can be no assurances that actual usage, delinquencies and charge-offs will
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not be significantly different from future forecasts thereof. The adjustment
mechanism for the FTA Charges described under "Description of the Transition
Property--Adjustments to the FTA Charges", as well as the collection of the
Overcollateralization Amount and the pledge of amounts deposited in the Capital
Subaccount, are intended to mitigate these risks, although the frequency of the
adjustments to the FTA Charges is limited and accordingly delays in
distributions to Certificateholders might result. See "The Seller and Servicer-
- -Credit Policy; Billing; Collections; Restoration of Service" herein.
DELAYS CAUSED BY CHANGES IN PAYMENT TERMS
The Servicer is permitted to alter the terms of billing and collection
arrangements and modify amounts due from Customers. While PG&E has no current
intention of taking actions that would change the billing and collection
arrangements in a manner which would affect adversely the collection of FTA
Payments, there can be no assurance that changes in PG&E's customary and usual
practices for comparable assets it services for itself might not result in a
determination to do so or that a successor Servicer may not make such a
determination. It is possible that any such changes could delay collections
from Customers or result in lower collections, and accordingly could adversely
affect the distribution of interest on the Certificates on a timely basis or the
distribution of the principal of the Certificates pursuant to the Expected
Amortization Schedules or in full by the applicable Scheduled Final Distribution
Dates. See "Certain Distribution and Weighted Average Life Considerations"
herein.
LIMITED CREDIT POLICY AND PROCEDURES
The ability of the Servicer to collect amounts billed to Customers
under the FTA Charges, as adjusted from time to time, will depend in part on the
creditworthiness of the Customers. PG&E generally is obligated to provide
service to new Customers under California law and generally no outside credit
investigations are performed on new Customers. PG&E's information regarding the
credit status of new Customers is limited to information regarding prior
service, if any, by PG&E to such Customers. PG&E relies on the information
provided by Customers and its customer information system audits to indicate
whether a new Customer has had previous service from PG&E. If PG&E evaluates
the creditworthiness of a significant number of its Customers incorrectly,
resulting in significant increases in delinquencies and write-offs, delays in
distributions to Certificateholders may occur. See "The Seller and Servicer--
Credit Policy; Billing; Collections; Restoration of Service" herein.
RELIANCE ON AGGREGATORS AND OTHER SUPPLIERS
As part of the deregulation of the California electric industry
described elsewhere herein, there will be an unbundling of generation,
transmission, distribution and billing services. A decision of the CPUC allows
alternative energy service providers ("ESPS") to elect to present a consolidated
bill to their retail customers covering amounts owed to the ESP for electricity,
amounts owed to the Utilities for distribution and the applicable FTA Charge.
Any ESP who elects consolidated billing will be responsible for paying the
Servicer monthly amounts payable by customers of the ESP regardless of the ESP's
ability to collect the FTA Charges from its customers, including monthly FTA
Payments. The CPUC has not yet made a final determination regarding the
appropriate credit standards to be required of ESPs, or the appropriate form of
the necessary agreement between PG&E and each ESP. There can be no assurance
that each ESP will have the same credit standards as the Servicer, or that the
Servicer will be able to mitigate credit risks relating to ESPs in the same
manner in which it mitigates such risks relating to its Customers. Neither the
Seller nor the Servicer will pay any shortfalls resulting from the failure of
any ESPs to forward FTA Payments to PG&E, as Servicer. The true-up adjustment
mechanism for the FTA Charges, as well as the collection of the
Overcollateralization Amount and the pledge of amounts
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deposited in the Capital Subaccount, are intended to mitigate this risk.
However, delays in distributions to Certificateholders might occur as a result
of delays in implementation of the adjustment mechanism.
COMMINGLING OF FTA PAYMENTS WITH SERVICER'S OTHER FUNDS; INVESTMENT OF FTA
PAYMENTS FOR SERVICER'S ACCOUNT
Except as described under "Servicing--Remittances to Collection
Account" herein, on each Remittance Date the Servicer will remit to the
Collection Account FTA Payments expected to have been received during the
preceding calendar month. Accordingly, FTA Payments received by the Servicer
will not be segregated from the Servicer's general funds until they are remitted
to the Collection Account, and the Servicer will invest FTA Payments received
but not yet remitted for its own account. A failure or inability of the
Servicer to remit the full amount of the estimated FTA Payments on any
Remittance Date, whether voluntary or involuntary, might result in delays in
distributions to Certificateholders. The true-up adjustment mechanism, as well
as the collection of the Overcollateralization Amount and the pledge of amounts
deposited in the Capital Subaccount, are intended to mitigate this risk.
However, delays in distributions to Certificateholders may occur as a result of
delays in implementation of the adjustment mechanism.
UNCERTAINTIES RELATED TO THE ELECTRIC INDUSTRY GENERALLY
UNTRIED NEW CALIFORNIA MARKET STRUCTURE
The California electric industry will change dramatically in the near
future, as a result of recent decisions by the CPUC and enactment of the
Statute. See "Energy Deregulation and New California Market Structure" herein.
The new California electric market structure, scheduled to begin January 1,
1998, has neither been tested nor implemented. Many elements of the new market
structure present novel regulatory issues yet to be resolved as well as many
practical issues of implementation such as the development of systems, software
and procedures for each of (a) the independent power exchange (the "PX"), which
will manage electricity supply and demand, (b) the independent system operator
(the "ISO"), which will have operational control of the Utilities' transmission
facilities, and (c) all of the market participants who will transact with the PX
and ISO. If the new market structure is not implemented in a timely and orderly
fashion, electricity generation, transmission and distribution may be adversely
affected, FTA Payments may not be made as expected, the Servicer's business may
be impacted or Certificateholders may fail to receive distributions of principal
and interest for other reasons.
CHANGING REGULATORY ENVIRONMENT
In addition to actions taken by the California Legislature and
regulation by the CPUC, the electric industry is also subject to federal law and
regulation by the Federal Energy Regulatory Commission (the "FERC"). At least
five bills were introduced into the 105th Congress, First Session, mandating the
deregulation of the electric utility industry on the state level. In general,
the bills provide for open competition in the furnishing of electricity to all
retail customers. As described above under "--Transition Property--Federal
Preemption of the Statute," at least one of the bills may prohibit the recovery
of FTA Charges; however, none of the bills have passed in committee. No
prediction can be made as to whether these bills, or any future proposed bills
to mandate the deregulation of the electric industry, will become law or, if
they become law, what their final form or effect would be. Any changes in the
existing legal structure regulating the electric industry might have an impact
on the manner in which electricity is distributed and payments
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therefor are collected, or on the Servicer and its business, and thus the
likelihood that Certificateholders will receive distributions in the amounts and
at the times scheduled.
CHANGES IN GENERAL ECONOMIC CONDITIONS AND ELECTRICITY USAGE
General economic conditions and technological changes that would
significantly alter power consumption or reduce the residential and small
commercial consumer base in the Seller's historical service area may affect
payments on the Notes and, accordingly, distributions on the Certificates.
Changes in business cycles, departures of Customers from the Seller's historic
service area, weather, occurrence of natural disasters such as earthquakes and
floods, implementation of energy conservation efforts and increased efficiency
of equipment all affect energy usage. If a sufficient number of Customers
reduce significantly their electricity consumption or cease consuming
electricity altogether, the FTA Charges, as adjusted from time to time through
True-Up Mechanism Advice Letters, as described herein, required to be paid by
each remaining Customer could become burdensome. See "--Transition Property--
Reliance on FTA Adjustments" herein.
RELIANCE ON BROAD BASE OF CUSTOMERS
The FTA Charges are relatively modest in amount on an individual
Customer basis, when imposed on the Seller's current base of Customers.
However, if one or more of the risks described under the heading "--
Uncertainties Relating to the Electric Industry Generally" or an unforeseen
catastrophe were to occur, the number of Customers on whom the FTA Charges would
be levied might be reduced significantly. Such a reduction would increase the
amount of the applicable FTA Charge for each Customer, which might cause more
Customers to avoid paying the applicable FTA Charge after the Rate Freeze Period
by leaving the Territory. If the number of Customers were to be substantially
reduced, the remaining Customers might be unable or unwilling to pay the FTA
Charges. Alternatively, a reduced number of Customers and corresponding higher
per kilowatt hour FTA Charges might increase the reluctance of the CPUC to allow
adjustments to the FTA Charges or provide greater incentive for the California
legislature to amend the Statute in a manner intended to reduce or eliminate the
FTA Charges in respect of the Transition Property. Although the Note Issuer
believes that the likelihood of this scenario occurring is remote, this result
might cause Certificateholders to fail to receive the full amount of
distributions to which they are entitled.
BANKRUPTCY AND CREDITORS' RIGHTS ISSUES
POTENTIAL BANKRUPTCY OF SELLER
The Seller will represent and warrant in the Sale Agreement that the
transfer of the Transition Property pursuant thereto to the Note Issuer is a
valid sale and assignment of such Transition Property from the Seller to the
Note Issuer. The Seller and the Note Issuer will also represent and warrant
that they will each take the appropriate actions under the PU Code to perfect
this sale. The Statute provides that the transactions described in the Sale
Agreement shall constitute a sale of the Transition Property to the Note Issuer,
and the Seller and the Note Issuer will treat the transactions as a sale under
applicable law, although for financial reporting purposes the transactions will
be treated as debt of the Seller. If the Seller were to become a debtor in a
bankruptcy case, and a creditor or bankruptcy trustee of the Seller or the
Seller itself as debtor in possession were to take the position that the sale of
the Transition Property to the Note Issuer should be recharacterized as a pledge
of such Transition Property to secure a borrowing of the Seller, and a court
were to adopt such position, then delays or reductions in distributions on the
Certificates could result.
The Seller and the Note Issuer have taken steps to ensure that in the
event the Seller or an affiliate of the Seller were to become the debtor in a
bankruptcy case, a court would not order that the assets and liabilities of the
Seller or such affiliate be substantively consolidated with those of the Note
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Issuer. The Note Issuer is a separate, limited purpose limited liability
company, the organizational documents of which provide that it shall not
commence a voluntary bankruptcy case without the unanimous affirmative vote of
all of its directors, and pursuant to the Trust Agreement, each holder of a
Certificate agrees that it will not commence an involuntary bankruptcy case
against the Note Issuer. Nonetheless, no assurance can be given that if the
Seller or an affiliate of the Seller were to become a debtor in a bankruptcy
case, a court would not order that the assets and liabilities of the Note Issuer
be consolidated with those of the Seller or such affiliate, thus resulting in
delays or reductions in distributions on the Certificates.
Should the transfer of the Transition Property to the Note Issuer be
recharacterized as a borrowing by the Seller, the Statute provides that there is
a perfected first priority statutory lien on the Transition Property that
secures all obligations to the holders of the Certificates. In addition, in the
Sale Agreement, the Seller grants to the Note Issuer a security interest in the
Transition Property, and covenants that the appropriate actions will be taken to
perfect such security interest. The Seller's First and Refunding Mortgage,
dated December 1, 1920, as amended, contains limits on the Seller's ability to
grant consensual security interests, and thus no assurances can be given that
any such security interest is valid or enforceable.
The Statute provides that any Transition Property constitutes a
current property right on the date that the Financing Order and the related
Issuance Advice Letter have become effective and that it thereafter exists
continuously for all purposes. Nonetheless, no assurances can be given that if
the Seller were to become the debtor in a bankruptcy case, a creditor of, or a
bankruptcy trustee for, the Seller or the Seller itself as debtor in possession
would not attempt to take the position that, because the payments based on the
FTA Charges are usage-based charges, Transition Property comes into existence
only as Customers use electricity. If a court were to adopt this position, no
assurances can be given that either the statutory lien created by the Statute or
the security interest purported to be granted in the Sale Agreement would attach
to collections of FTA Payments in respect of electricity consumed after the
commencement of a bankruptcy case for the Seller. If it were determined that
the Transition Property has not been sold to the Note Issuer, and that the
statutory lien created by the Statute and the security interest purported to be
granted in the Sale Agreement do not attach to collections of FTA Payments in
respect of electricity consumed after the commencement of a bankruptcy case for
the Seller, then the Certificate Trustee, as Noteholder and for the benefit of
holders of the Certificates, would be an unsecured creditor of the Seller, and
delays or reductions in distributions on the Certificates could result. Whether
or not the court determined that the Transition Property had been sold to the
Note Issuer, no assurances can be given that the court would not rule that any
FTA Payments relating to electricity consumed after the commencement of the
Seller's bankruptcy cannot be transferred to the Note Issuer or the Certificate
Trustee, thus resulting in delays or reductions of distributions on the
Certificates.
Because the payments based on the FTA Charges are usage-based charges,
if the Seller were to become the debtor in a bankruptcy case, a creditor of, or
a bankruptcy trustee for, the Seller, or the Seller itself as debtor in
possession could take the position that the Note Issuer should pay a portion of
the costs of the Seller associated with the generation, transmission, or
distribution by the Seller of the electricity whose consumption gave rise to the
FTA Collections that are used to make distributions on the Certificates. If a
court were to adopt this position, the result could initially be a reduction in
the amounts paid to the Note Issuer, and thus to the holders of the
Certificates.
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The FTA Charges may be adjusted through True-Up Mechanism Advice Letters,
although delays in implementation thereof may cause a delay in receipt of
scheduled distributions.
Regardless of whether the Seller is the debtor in a bankruptcy case,
if a court were to accept the arguments of a creditor of the Seller that
Transition Property comes into existence only as Customers use electricity, a
tax or government lien or other nonconsensual lien on property of the Seller
arising before the Transition Property came into existence may have priority
over the Note Issuer's interest in such Transition Property, thereby possibly
initially resulting in a reduction of amounts distributed to the holders of the
Certificates. The FTA Charges may be adjusted through True-Up Mechanism Advice
Letters, although delays in implementation thereof may cause a delay in receipt
of scheduled distributions.
POTENTIAL BANKRUPTCY OF SERVICER
For so long as the Servicer maintains a short-term debt rating of at
least "A-1" by Standard & Poor's, a division of The McGraw-Hill Companies, Inc.
("S&P") and "P-1" by Moody's Investors Service, Inc. ("MOODY'S") or certain
other conditions are satisfied, the Servicer is entitled to commingle FTA
Payments with its own funds until the relevant Remittance Date. In the event of
a bankruptcy of the Servicer, the Note Trustee will likely not have a perfected
interest in such commingled funds and the inclusion thereof in the bankruptcy
estate of the Servicer may result in delays in distributions due on the
Certificates. See "--Servicing--Reliance on Servicer" herein.
POTENTIAL BANKRUPTCY OF INFRASTRUCTURE BANK
The Infrastructure Bank is a public body established within the state
government of the State of California. The State of California cannot be a
debtor in a case under the Bankruptcy Code. If a court were to determine that
the Infrastructure Bank is an "instrumentality" of the State, rather than an
integral part of the State, then the Infrastructure Bank could become a debtor
in a case commenced under Chapter 9 of the Bankruptcy Code if the requirements
set forth in the Bankruptcy Code for the commencement of a voluntary case under
Chapter 9 were met. An involuntary case cannot be commenced against the
Infrastructure Bank under Chapter 9, and neither a voluntary nor an involuntary
case can be commenced by or against the Infrastructure Bank under any other
chapter of the Bankruptcy Code.
The Certificates will be issued by the Trust, which is a business
trust formed by the Infrastructure Bank under Title 12, Chapter 38 of the Laws
of the State of Delaware (the "DELAWARE BUSINESS TRUST ACT"). The Trust may be
subject to a voluntary or involuntary case under the Bankruptcy Code. However,
the Trust will be created solely to issue and administer the Certificates, and
the only assets of the Trust will consist of the Notes. The Trust and the
Infrastructure Bank have taken steps to ensure that in the event the
Infrastructure Bank becomes a debtor in a case under Chapter 9 of the Bankruptcy
Code, a bankruptcy court having jurisdiction over such case should not order
that the assets and liabilities of the Trust be substantively consolidated with
those of the Infrastructure Bank. These steps include (a) creating the Trust as
a separate business trust under the Delaware Business Trust Act which includes
provisions preventing creditors of the Infrastructure Bank from having any right
to the assets of the Trust, (b) limiting interaction between the Infrastructure
Bank and the Trust, (c) maintaining accounting, bookkeeping, business forms and
financial statements for the Trust separate from those of the Infrastructure
Bank, and (d) restricting the nature of the Trust's business and its ability to
commence a voluntary case under the Bankruptcy Code.
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NATURE OF THE CERTIFICATES
LIMITED LIQUIDITY
There is no assurance that a secondary market for any of the
Certificates will develop or, if one does develop, that it will provide the
Certificateholders with liquidity of investment or that it will continue for the
life of such Certificates. It is not anticipated that any Certificates will be
listed on any securities exchange.
RESTRICTIONS ON BOOK-ENTRY REGISTRATION
The Certificates will be initially represented by one or more
Certificates registered in Cede's name, as nominee for DTC, and will not be
registered in the names of the Certificateholders or their nominees. Therefore,
unless and until Definitive Certificates are issued, Certificateholders will
not be recognized by the Certificate Trustee as Certificateholders. Hence,
until such time, Certificateholders will only be able to receive distributions
from, and exercise the rights of Certificateholders indirectly through, DTC and
participating organizations, and, unless a Certificateholder requests a copy of
any such report from the Certificate Trustee or the Servicer, will receive
reports and other information provided for under the Servicing Agreement only
if, when and to the extent provided to Certificateholders by DTC and its
participating organizations. In addition, the ability of Certificateholders to
pledge Certificates to persons or entities that do not participate in the DTC
system, or otherwise take actions in respect of such Certificates, may be
limited due to the lack of physical certificates for such Certificates. See
"Description of the Certificates--Book-Entry Registration" herein.
LIMITED OBLIGATIONS
Neither the Notes nor the Certificates will represent an interest in
or obligation of the Seller, the State of California or the Infrastructure Bank.
The Transition Property owned by the Note Issuer and the other Note Collateral,
which is expected to be relatively small, are the sole source of payments on the
Notes. It is anticipated that the Note Collateral, which is described under
"Description of the Notes--Security" herein, will with limited exceptions
specified therein constitute the Note Issuer's only assets. The Note Issuer's
organizational documents will restrict its right to acquire other assets
unrelated to the transaction described herein. The Notes are limited
obligations of the Note Issuer, and are the sole assets of the Trust other than
the Trust's rights under any Swap Agreement. The Certificates represent
undivided interests in the Trust, and the sole source of distributions thereon
is the payments on the Notes and, in the event of variable-rate Certificates,
the proceeds of any Swap Agreement. If distributions are not made on the
Certificates in a timely manner as a result of nonpayment of the related Notes,
the Certificateholders may direct the Certificate Trustee to bring an action
against the Note Issuer to foreclose upon the Transition Property and the other
Note Collateral securing the Notes and, if the Certificate Trustee fails to
bring such action, the Certificateholders may bring such an action themselves,
as described under "Description of the Certificates--Events of Default" herein.
None of the Certificates, the Notes or the underlying Transition Property will
be guaranteed or insured by the State of California, the Infrastructure Bank or
any other governmental agency or instrumentality or by the Seller or its
affiliates. Neither the full faith and credit nor the taxing power of the State
of California is pledged to the payment of principal of or interest on the
Certificates or the Notes or the payments in respect of the Transition Property.
ISSUANCE IN SERIES
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The Note Issuer expects to issue new Series of Notes from time to
time, and accordingly the Trust is expected to issue new corresponding Series of
Certificates from time to time. While the terms of any Series of Notes and the
corresponding Series of Certificates will be specified in supplements to the
Note Indenture and the Trust Agreement, respectively, and described in the
related Prospectus Supplement, the provisions of supplements to the Note
Indenture and the Trust Agreement and, therefore, the terms of any new Series,
will not be subject to the prior review or consent of holders of the Notes or
Certificates of any previously issued Series. The terms of a new Series of
Certificates may include without limitation the matters described under
"Description of the Certificates--General" herein. The ability of the Trust to
issue any new Series of Certificates is subject to the condition, among others,
that such issuance will not result in any Rating Agency reducing or withdrawing
its then existing rating of the Certificates of any outstanding Class. There
can be no assurance, however, that the issuance of any other Series of
Certificates, including any Series issued from time to time hereafter, might not
have an impact on the timing or amount of distributions received by a
Certificateholder. See "Description of the Certificates--Conditions of Issuance
of Additional Series" herein.
LIMITED NATURE OF RATINGS
It is a condition of issuance of each Class of Certificates that they
receive from the Rating Agencies the respective ratings set forth in the
applicable Prospectus Supplement. The ratings of the Certificates address the
likelihood of the ultimate distribution of principal and the timely distribution
of interest on the Certificates. The ratings do not represent an assessment of
the likelihood that the rate of FTA Collections might differ from that
originally anticipated; as a result of such differences, any Series or Class of
Certificates might mature later than scheduled, resulting in a weighted average
life of such Certificates which is more than expected. A security rating is not
a recommendation to buy, sell or hold securities. There can be no assurance
that a rating will remain in effect for any given period of time or that a
rating will not be revised or withdrawn entirely by a Rating Agency if, in its
judgment, circumstances so warrant.
UNCERTAIN DISTRIBUTION AMOUNTS AND WEIGHTED AVERAGE LIFE
The actual dates on which principal is paid on each Class of
Certificates might be affected by, among other things, the amount and timing of
receipt of FTA Collections. Since each FTA Charge will consist of a charge per
kilowatt hour of usage by the applicable class of Customers in the Territory,
the aggregate amount and timing of FTA Collections (and the resulting amount and
timing of principal amortization on the Certificates) could depend, in part, on
actual usage of electricity by Customers and the rate of delinquencies and
charge-offs. See "--Inaccurate Usage and Credit Projections" herein. Although
the amount of the FTA Charges will adjust from time to time based in part on the
actual rate of FTA Collections during prior Billing Periods, no assurances can
be given that the Servicer will be able to forecast accurately actual Customer
energy usage and the rate of delinquencies and charge-offs and implement
adjustments to the FTA Charges that will cause FTA Payments to be made at any
particular rate. If FTA Collections are received at a slower rate than
expected, distributions on a Certificate may be made later than expected.
Because principal will only be distributed in accordance with the Expected
Amortization Schedules, except in the event of an early redemption, the
Certificates are not expected to be retired earlier than scheduled. A
distribution on a date that is earlier than forecasted will result in a shorter
weighted average life, and a distribution on a date that is later than
forecasted will result in a longer weighted average life. See "Certain
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Distribution and Weighted Average Life Considerations" and "Description of the
Transition Property--Adjustments to the FTA Charges" herein.
EFFECT OF OPTIONAL REDEMPTION ON WEIGHTED AVERAGE LIFE
As described more fully under "Description of the Notes--Optional
Redemption" herein, the Note Issuer has the option to redeem all of the
outstanding Notes of any Series at any time after the outstanding principal
balance thereof has been reduced to less than five percent of the initial
outstanding principal balance. Redemption of a Series of Notes will require the
Certificate Trustee to redeem the related Series of Certificates. Redemption
will cause such Certificates to be retired earlier than would otherwise be
expected, and if the payment schedule otherwise does not differ from that
originally anticipated, will result in a shorter than expected weighted average
life for such Certificates. There can be no assurance as to whether the Note
Issuer will exercise the option to redeem any Series of Notes, or as to whether
Certificateholders will be able to receive an equally attractive rate of return
upon reinvestment of the proceeds resulting from any such redemption.
LIMITATIONS, REDUCTION AND SUBSTITUTION OF CREDIT ENHANCEMENTS
With respect to each Series of Certificates, credit enhancement may be
provided in limited amounts to cover certain types of shortfalls or losses.
Credit enhancement will be provided in one or more forms, including but not
limited to subordination of other Classes of Certificates of the same Series, a
letter of credit or any combination thereof. Regardless of the form of credit
enhancement provided, the amount of coverage will be limited in amount and in
most cases will be subject to periodic reduction in accordance with a schedule
or formula. Furthermore, such credit enhancements may provide only very limited
coverage as to certain types of shortfalls, losses or risks, and may provide no
coverage as to certain other types of shortfalls, losses or risks. All or a
portion of the credit enhancement for any Series or Class of Certificates will
generally be permitted to be reduced, terminated or substituted for, if the
Rating Agency Condition is satisfied. The rating of any Series or Class of
Certificates by any applicable Rating Agency may be lowered following the
initial issuance thereof as a result of the downgrading of the obligations of
any applicable credit support provider, or as a result of shortfalls or losses
on the Transition Property in excess of the levels contemplated by such Rating
Agency at the time of its initial rating analysis. Neither the Seller, the
Servicer, the Note Issuer, the Infrastructure Bank, the Trust nor any of their
affiliates will have any obligation to replace or supplement any credit
enhancement, or to take any other action to maintain any rating of any Series or
Class of Certificates. In the event shortfalls or losses exceed the amount of
coverage provided by any credit enhancement or shortfalls or losses of a type
not covered by any credit enhancement occur, such shortfalls or losses will be
borne by the holders of the related Certificates (or certain Classes thereof).
ENERGY DEREGULATION AND NEW CALIFORNIA MARKET STRUCTURE
The electric industry is experiencing intensifying competitive pressures,
particularly in the wholesale generation and industrial customer markets.
Historically, electric utilities operated as regulated monopolies in their
service territories, pursuant to which they were the sole suppliers of
electricity, and in California their rates were set by the CPUC based upon the
utilities' cost of providing services and a reasonable return on their capital
investments. The National Energy Policy Act of 1992 was designed to increase
competition in the wholesale electric generation market by easing regulatory
restrictions on producers of wholesale power and by authorizing the FERC to
mandate access to electric transmission systems by wholesale power generators.
At least five bills have been introduced in the 105th Congress, First
Session, which would mandate the deregulation of the electric industry on the
state level; however, none of these bills have passed in
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committee. In their current forms, some but not all of the bills contain
provisions recognizing the validity of prior state actions relating to
deregulation. At least one of the bills, H.R. 1230, prohibits the recovery of
stranded costs such as the Transition Costs. The entire California delegation to
Congress has signed a letter to the chairman of the House Subcommittee
responsible for holding hearings regarding the bills, which expresses the shared
concern that the effect of the Statute should not be impacted by federal
legislation. No prediction can be made as to whether any of these bills, or any
future proposed bills to deregulate the electric industry, will become law or,
if they become law, what their final form or effect will be.
The California electric industry will change dramatically in the near
future as a result of recent decisions by the CPUC and enactment of the Statute.
Among other things, the PX will create a competitive market for electric energy
in California through the creation of a wholesale power pool where all
suppliers, including the Utilities, municipal utilities, power marketing
agencies, independent power producers, and out-of-state generators, will have
the opportunity to sell electricity through the pool according to established
competitive bidding procedures with winning bids awarded to those suppliers that
bid to supply electricity at the lowest price. In addition, the Utilities will
be required, and other transmission owners will be permitted, to place certain
of their transmission facilities under the operational control of the ISO.
Ownership and maintenance of the transmission lines will remain with the
transmission line owners. All power suppliers will receive nondiscriminatory
access to the transmission grid under the control of the ISO and will be subject
to the same protocols and pricing procedures. Customers will have the
opportunity to choose the generators from whom they purchase their electricity.
Notwithstanding these changes, the Utilities are expected to continue to be the
sole providers of electricity distribution services within their service
territories. The Utilities will be encouraged, through CPUC-established
incentives, to divest at least 50 percent of their fossil-fueled electricity
generation assets, in order to address market dominance issues.
The changes which are occurring at both the federal and the California
levels will have a significant impact on PG&E and the other Utilities, as well
as other entities in the industry. PG&E faces greater competition for resources
and for customers. Competitors include privately owned independent power
producers, exempt wholesale power generators, industrial customers developing
their own generation resources, suppliers of natural gas and other fuels, other
investor-owned electric utilities and municipal generators. There can be no
assurance that such trends will not have a significant adverse impact on PG&E's
business in the future.
DESCRIPTION OF THE TRANSITION PROPERTY
GENERAL
In September 1996, legislation implementing an electric industry
restructuring program for the State of California became law. The legislation,
which as amended is referred to herein as the Statute, was adopted to provide,
among other things, subject to the timely and sufficient issuance of rate
reduction bonds, a ten percent reduction in rates for services charged to
Residential Customers and Small Commercial Customers, effective as of January 1,
1998 and generally continuing until the earlier of March 31, 2002 or the date on
which transition costs have been fully recovered (the "RATE FREEZE PERIOD"). As
part of this legislation, Sections 367 and 369 of the PU Code generally provide
the Seller an opportunity to recover the Transition Costs. The Transition Costs
consist of the costs of generation-related assets and obligations that may
become uneconomic as a result of a competitive generation market, together with
costs for capital additions to generating facilities that the CPUC determines to
be reasonable, costs of refinancing or retiring of debt or equity capital, and
associated federal and state tax liabilities. Examples of generation-related
assets include such things
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as generation facilities, generation-related regulatory assets, amounts
recoverable in electric rates pursuant to settlement agreements with the CPUC in
connection with nuclear power plants, and power purchase contracts with third-
party generators of electricity (including voluntary restructuring,
renegotiations or terminations thereof). These assets may become uneconomic in
a competitive generation market, since they are obligations that were undertaken
either pursuant to legal requirements or with the understanding that they would
be recoverable in rates approved by the CPUC. Since other participants in a
competitive market, unburdened by these uneconomic assets, may be able to offer
electricity at lower rates, the costs relating to these uneconomic assets may
not be recoverable in market prices in a competitive market.
The Statute created the Transition Property, which is the right to be paid
the FTA Payments based on the FTA Charges in order to recover the Transition
Costs.
FINANCING ORDER AND ADVICE LETTERS
The Statute authorizes the CPUC to issue the Financing Order, a regulatory
order which allows the Seller to reduce electricity rates for the Customers by
ten percent, and approves the amount of the Seller's Transition Costs which the
Seller is permitted to finance through the issuance of rate reduction bonds. On
May 6, 1997, PG&E filed its application for the Financing Order with the CPUC.
The CPUC issued the Financing Order as of September 3, 1997. The Financing
Order also permits the sale of Certificates in an aggregate principal amount not
to exceed $3,500,000,000. As issued, the Financing Order also requires the
Seller to reduce electricity rates for the Customers by ten percent through the
Rate Freeze Period. The principal amount of the Certificates approved in the
Financing Order was calculated so as to result in a reduction in revenue
requirements for the Seller sufficient to finance the ten percent rate
reduction. The principal amount of the Certificates was derived based upon a
number of variables, including sales forecasts and the expected interest rate
and amortization schedule for the Certificates. If estimated usage exceeds the
assumptions used in the Financing Order, the Seller intends to request the
issuance of additional Certificates to finance the rate reduction resulting from
this increased usage. The issuance of additional Certificates will result in a
corresponding increase in the FTA Charges, and thus in the amounts payable with
respect thereto by Customers. See "Description of the Certificates--Conditions
of Issuance of Additional Series" herein.
The Financing Order provides for the establishment, among other things, of
tariffs referred to as the FTA Charges, which constitute separate nonbypassable
charges upon Residential Customers and Small Commercial Customers in an
aggregate amount sufficient to repay in full the Certificates and associated
costs and fees. The FTA Charges are stated to be nonbypassable on the basis
that the Statute authorizes the Seller to continue to collect payments based on
the FTA Charges from all Customers notwithstanding any of the circumstances
described under "--Nonbypassable FTA Charges" below. The Statute provides that
the right to collect payments based on the FTA Charges is a property right which
may be pledged, assigned or sold in connection with the issuance of the
Certificates.
The Financing Order entitles the Note Issuer, as the owner of the
Transition Property, to receive the payments made pursuant to the FTA Charges
from all Residential Customers and Small Commercial Customers. Such payments
are referred to herein as the FTA Payments.
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The Financing Order requires the Seller to submit an Issuance Advice Letter to
the CPUC with respect to each Series of Certificates issued. The first Issuance
Advice Letter will establish the initial FTA Charges. The Financing Order
provides that Issuance Advice Letters become effective five business days after
filing with the CPUC. Subsequent Issuance Advice Letters may increase the FTA
Charges to support the issuance of additional Series of Certificates. The
Financing Order permits the Servicer to file True-Up Mechanism Advice Letters to
modify the FTA Charges from time to time, in order to enhance the likelihood of
retirement of each Series and Class of Certificates on a timely basis. See "--
Adjustments to the FTA Charges" herein.
The initial FTA Charges will be calculated by determining (i) projected
monthly electricity sales for the Customers and the timing and extent of receipt
of payments therefor and (ii) the FTA Collections on a projected basis,
including interest on the Notes, ongoing transaction expenses including the
Servicing Fee, the related Overcollateralization Amount and scheduled principal
payments on the Notes; based on the figures determined for the two foregoing
amounts, the lowest aggregate charge which will be adequate to cover all of the
amounts to be covered by FTA Collections will be calculated (the "BASE
CALCULATION MODEL"). Because of differences in the tariff rate for each class
of Customers, the FTA Charge payable by Residential Customers is expected to be
different from the FTA Charge payable by Small Commercial Customers; the initial
FTA Charges will result in FTA Payments by the Residential Customers and Small
Commercial Customers representing approximately __% and __%, respectively, of
the aggregate FTA Payments. The foregoing percentages may change from time to
time based on fluctuations in Customer composition.
The Prospectus Supplement related to a Series of Certificates will specify,
based on the applicable Issuance Advice Letter, the amount of each of the FTA
Charges as of the date thereof.
TRANSITION PROPERTY
The right to be paid the FTA Payments gives rise to a separate property
right under California law and is referred to herein generally as the
"Transition Property." "Transition Property" is defined more specifically in
Section 840(g) of the PU Code as the property right created under the PU Code
including, without limitation, the right, title and interest of an electrical
corporation or its transferee (i) in and to the FTA Charges, as adjusted from
time to time, (ii) to be paid the FTA Payments, and (iii) to obtain adjustments
to the FTA Charges, as provided in the PU Code.
Each Class of Notes will be issued in connection with a specific issuance
of a Class of Certificates. Each Note will be secured by Transition Property,
as well as the other Note Collateral described under "Description of the Notes--
Security" herein. Following the initial Issuance Advice Letter, each subsequent
Issuance Advice Letter will authorize the creation of additional Transition
Property to support payments on the related Series or Class of Notes. Any
additional Transition Property acquired by the Note Issuer pursuant to a Sale
Agreement will be combined into a single asset with all other Transition
Property acquired by the Note Issuer pursuant to previous Sale Agreements.
Accordingly, the aggregate amount of Transition Property will increase as
additional Issuance Advice Letters become effective.
NONBYPASSABLE FTA CHARGES
The Financing Order provides that the FTA Charges are nonbypassable,
meaning that Customers will still be required to make payments with respect to
the applicable FTA Charge, even if a Customer elects to purchase electricity
from another supplier, another entity takes over a portion of PG&E's existing
service territory or a Small Commercial Customer's load increases so
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that such Customer is no longer a Small Commercial Customer. The Financing
Order provides that each Customer who leaves PG&E's system during the Rate
Freeze Period through annexation by another electricity supplier will pay an
ongoing charge based on the electricity usage of such Customer prior to
annexation. The Financing Order provides that each Customer who ceases to be a
Small Commercial Customer as a result of increased electricity usage will
continue to pay the applicable FTA Charge, based on either (i) the last twelve
months of the Customer's recorded pre-departure use, (ii) an average derived
from the last three years of recorded use or (iii) actual use; provided,
however, that any such Customer will have the opportunity to continue to pay for
electricity based on the Small Commercial Customer rates, including the
applicable FTA Charge.
ADJUSTMENTS TO THE FTA CHARGES
In order to enhance the likelihood that actual FTA Collections are neither
more nor less than the amount necessary to amortize the Certificates in
accordance with the Expected Amortization Schedule and fund the
Overcollateralization Subaccount, the Servicing Agreement requires the Servicer
to seek, and the Financing Order and the Statute require the CPUC to approve,
periodic adjustments to the FTA Charges based on actual FTA Collections and
updated assumptions by the Servicer as to future usage of electricity by
Customers, future expenses relating to the Transition Property, the Notes and
the Certificates, and the rate of delinquencies and charge-offs. The date as of
which any calculation is performed and which forms the basis for a requested
adjustment to the FTA Charges is referred to as a "CALCULATION DATE." The
adjustments to the FTA Charges will continue until all interest and principal on
all Series of Notes and corresponding Series of Certificates have been paid or
distributed in full.
The Financing Order provides that the Servicer will file a routine True-Up
Mechanism Advice Letter annually, requesting modifications to the FTA Charges
which are intended to return the projected principal balance of each outstanding
Series of Certificates to the amount provided for in the Expected Amortization
Schedule within a twelve month period or, if earlier, by the Scheduled Final
Distribution Date and to fund the Overcollateralization Subaccount as scheduled.
Calculations of appropriate modifications to the FTA Charges will be made based
on the Base Calculation Model, except that (i) the amount of debt service and
related expenses including funding of the Overcollateralization Subaccount for
the following year shall be increased or decreased to reflect the amount by
which actual FTA Collections remitted to the Collection Account through the end
of the month preceding the month of calculation was less than or exceeded the
aggregate actual portion of the debt service on the Certificates and related
expenses for such period, (ii) forecasted electricity sales for the remaining
period of the transaction will be revised based on the methodology described in
the Financing Order, (iii) estimated transaction expenses will be modified to
reflect changed circumstances, (iv) assumed delinquencies and charge-offs will
be modified to reflect changed circumstances and (v) an adjustment will be made
to reflect any collections which are expected to be received at the existing
tariff rate from the end of the month preceding the month of calculation through
the end of the month in which the new FTA Charges become effective (the "TRUE-UP
MECHANISM CALCULATION MODEL").
The Servicer will also file a routine True-Up Mechanism Advice Letter
quarterly, if, the amount of FTA Payments causes the aggregate outstanding
principal balance of the Certificates to vary from the amount provided for in
the Expected Amortization Schedule for all outstanding Certificates as of any
Calculation Date by more than an amount to be specified in each Prospectus
Supplement or if amounts on deposit in the Collection Account vary from amounts
specified in each Prospectus Supplement. Furthermore, the Financing Order
provides that the Servicer may file a non-routine True-Up Mechanism Advice
Letter as often as quarterly, to reflect any
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changes to the Base Calculation Model or True-Up Mechanism Calculation Model
which are necessary to meet any Expected Amortization Schedule and fund the
Collection Account as scheduled. Finally, the Statute requires the Servicer to
file a True-Up Mechanism Advice Letter with the CPUC annually, prior to each
anniversary of the issuance of the Financing Order (a "FINANCING ORDER
ANNIVERSARY").
The Servicing Agreement will require the Servicer to deliver a written copy
of each True-Up Mechanism Advice Letter, together with a copy of all supporting
calculations, to the Note Issuer, the Note Trustee, the Infrastructure Bank and
the Certificate Trustee upon filing such True-Up Mechanism Advice Letter with
the CPUC.
The Financing Order provides that (i) routine True-Up Mechanism Advice
Letters shall be filed with the CPUC annually at least 15 days before the end of
each calendar year, with resulting adjustments to the FTA Charges to become
effective at the beginning of the next calendar year, (ii) routine True-Up
Mechanism Advice Letters may be filed with the CPUC quarterly at least 15 days
before the end of each calendar quarter, with resulting adjustments to the FTA
Charges to become effective at the beginning of the next calendar quarter, (iii)
non-routine True-Up Mechanism Advice Letters may be filed with the CPUC
quarterly at least 90 days before the end of each calendar quarter, with
resulting adjustments to the FTA Charges to become effective at the beginning of
the next calendar quarter, and (iv) True-Up Mechanism Advice Letters shall be
filed with the CPUC at least 15 days before each Financing Order Anniversary,
with resulting adjustments to the FTA Charges, if necessary, to become effective
within 90 days of such Financing Order Anniversary.
SALE AND ASSIGNMENT OF TRANSITION PROPERTY
On the date on which the initial Series of Certificates is issued and sold
(the "CLOSING DATE"), pursuant to the Sale Agreement the Seller will sell and
assign to the Note Issuer, without recourse, its entire interest in the
Transition Property which is described in the first Issuance Advice Letter
submitted by the Servicer (the "INITIAL TRANSITION PROPERTY"). The net proceeds
received by the Note Issuer from the sale of the Notes will be applied to the
purchase of the Initial Transition Property. Thereafter, in order to finance
the cost of the ten percent rate reduction the Seller may agree with the Note
Issuer to sell additional Transition Property ("SUBSEQUENT TRANSITION PROPERTY")
to the Note Issuer, subject to the satisfaction of certain conditions. Such
Subsequent Transition Property will be sold to the Note Issuer effective on a
date (a "SUBSEQUENT TRANSFER DATE") specified in the written agreement between
the Seller and the Note Issuer. The Note Issuer will issue and sell additional
Notes to the Trust, and the Trust will issue and sell additional Certificates,
in connection therewith.
To promote uniform quality in servicing the Transition Property and to
reduce administrative costs, the Note Issuer will appoint the Servicer as
custodian of the documentation relating to the Transition Property. The
Seller's data systems will reflect the sale and assignment of the Transition
Property to the Note Issuer. The Seller's financial statements will indicate
that the Transition Property has been sold to the Note Issuer and will not be
available to creditors, although for financial reporting purposes the Seller
will treat the Transition Property as representing debt of the Seller.
Subsequent Transition Property may be sold by the Seller to the Note Issuer
from time to time, solely in connection with the issuance and sale of additional
Notes by the Note Issuer and of corresponding additional Certificates by the
Trust.
Any conveyance of Subsequent Transition Property is subject to the following
conditions, among others:
(a) the Seller shall have entered into a written sale agreement with
the Note Issuer;
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(b) the Seller shall have filed an Issuance Advice Letter with the
CPUC relating to such Subsequent Transition Property, which Issuance Advice
Letter shall have become effective;
(c) as of the applicable Subsequent Transfer Date, the Seller shall
not be insolvent and shall not be made insolvent by such conveyance;
(d) the Rating Agency Condition shall have been satisfied with
respect to such conveyance;
(e) such conveyance will not result in an adverse tax consequence to
the Trust or the Certificateholders;
(f) as of the applicable Subsequent Transfer Date, no breach by the
Seller of its representations, warranties or covenants in the applicable
Sale Agreement shall exist; and
(g) as of the applicable Subsequent Transfer Date, the Note Issuer
shall have sufficient funds available to pay the purchase price for the
Subsequent Transition Property to be transferred on such date and all
conditions to the issuance of new series of Notes and Certificates shall
have been satisfied or waived.
SELLER REPRESENTATIONS AND WARRANTIES
In the initial Sale Agreement and each subsequent Sale Agreement, the
Seller will make representations and warranties to the Note Issuer to the
effect, among other things, that: (a) the information provided by the Seller to
the Note Issuer with respect to the applicable Transition Property is correct in
all material respects; (b) at the Closing Date, the applicable Transition
Property is owned by the Seller and is free and clear of all security interests,
liens, charges and encumbrances, no offsets, defenses or counterclaims exist or
have been asserted or threatened with respect thereto and the Seller, in its
capacity as Seller or Servicer, will not at any time assert any security
interest, lien, charge or encumbrance against or with respect to any applicable
Transition Property; (c) at the Closing Date, the applicable Transition Property
has been validly transferred and sold to the Note Issuer and all filings
(including filings with the CPUC under the PU Code) necessary in any
jurisdiction to give the Note Issuer a first perfected ownership interest in the
applicable Transition Property shall have been made; (d) the Financing Order and
each Issuance Advice Letter pursuant to which any applicable Transition Property
has been created are valid, binding and irrevocable; (e) the assumptions used in
calculating the FTA Charges related to the applicable Transition Property are
reasonable and made in good faith; (f) the Seller is a corporation duly
organized and in good standing under the laws of the State of California, with
power and authority to own its properties and conduct its business as currently
owned or conducted and to execute, deliver and perform the terms of the Sale
Agreement; (g) the execution, delivery and performance of the Sale Agreement
have been duly authorized by the Seller by all necessary corporate action; (h)
the Sale Agreement constitutes a legal, valid and binding obligation of the
Seller, enforceable against the Seller in accordance with its terms; (i) the
consummation of the transactions contemplated by the Sale Agreement do not
conflict with the Seller's articles of incorporation or bylaws or any material
agreement to which the Seller is a party or bound, result in the creation or
imposition of any lien upon the Seller's properties or violate any law or any
order, rule or regulation applicable to the Seller; (j) no governmental
approvals, authorizations or filings are required for the Seller to execute,
deliver and perform its obligations under the Sale Agreement except those which
have previously been obtained or made; and (k) except as disclosed to the Note
Issuer, no court or administrative proceeding or investigation is pending or, to
the Seller's knowledge, threatened (i) asserting the invalidity of, or seeking
to prevent the consummation of the transactions contemplated by, the Sale
Agreement, the Note Indenture, the Trust Agreement or any of the other Basic
Documents, (ii) seeking a determination that might materially and adversely
affect the performance by the
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Seller of its obligations thereunder, or (iii) which might adversely affect the
federal or state income tax attributes of the Notes or the Certificates.
In the event of a breach by the Seller of any of its representations and
warranties described in the preceding paragraph, the Seller will indemnify,
defend and hold harmless the Note Issuer, the Trust, the Noteholders, the Note
Trustee, the Delaware Trustee, the Certificate Trustee, the Certificateholders
and the Infrastructure Bank against any costs, expenses, losses, claims, damages
and liabilities incurred as a result thereof.
CERTAIN DISTRIBUTION AND WEIGHTED AVERAGE LIFE CONSIDERATIONS
The rate of principal distributions on each Class of Certificates, the
aggregate amount of each interest distribution on each Class of Certificates and
the actual maturity date of each Class of Certificates will be related to the
rate and timing of FTA Collections.
The actual distributions on each date for each Class of Certificates and
the weighted average life thereof will be affected primarily by the rate of FTA
Collections and the timing of receipt of such FTA Collections. Since the FTA
Charges will consist of a charge per kilowatt hour of usage by the applicable
classes of Customers, the aggregate amount of FTA Collections and the rate of
principal amortization on the Certificates will depend, in part, on actual
energy usage by Customers and the rate of delinquencies and charge-offs.
Although the amounts of the FTA Charges will be adjusted from time to time based
in part on the actual rate of FTA Collections, no assurances are given that the
Servicer will be able to forecast accurately actual energy usage and the rate of
delinquencies and charge-offs or implement adjustments to the FTA Charges that
will cause FTA Collections to be received at any particular rate. If FTA
Collections are received at a slower rate than expected a Certificate may be
retired later than expected. Because principal will only be distributed in
accordance with the Expected Amortization Schedules, except in the event of an
early redemption, the Certificates are not expected to mature earlier than
scheduled. A distribution on a date that is earlier than forecasted will result
in a shorter weighted average life, and a distribution on a date that is later
than forecasted will result in a longer weighted average life. In addition, if
a larger portion of the delayed distributions on the Certificates are received
in later years, this will result in a longer weighted average life of the
Certificates.
No representation is made as to the particular factors that will affect the
rate of FTA Collections, as to the relative importance of such factors, as to
the percentage of the principal balance of the Certificates that will be
distributed as of any date or as to the overall rate of FTA Collections.
THE TRUST
The Trust will be specifically created for the purpose of acquiring the
Notes. The Trust will be formed under the laws of the State of Delaware
pursuant to the Trust Agreement to be entered into among the Infrastructure
Bank, the Delaware Trustee and the Certificate Trustee, each such trustee not in
its individual capacity but acting as trustee on behalf of the holders of the
Certificates. The Trust will not be an agency or instrumentality of the State
of California. The Trust will have no assets other than the Notes and the
Trust's rights under any Swap Agreement. The Trust Agreement will not permit
the Trust to engage in any activities other than holding such assets, issuing
the Certificates, acting as paying agent and engaging in certain other
activities related thereto.
Each Class of Certificates offered hereby will represent a fractional
undivided interest in the corresponding Class of Notes, including all monies due
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and to become due under such corresponding Class of Notes, and will represent
the right to receive a portion of the payments of principal of and interest on
the corresponding Class of Notes, together with payments pursuant to any related
Swap Agreement. See "The Certificates--Payments and Distributions" herein.
The Fee and Indemnity Agreement among the Note Issuer, the Note Trustee,
the Infrastructure Bank, the Delaware Trustee and the Certificate Trustee (the
"FEE AGREEMENT") will provide that the Note Issuer will pay the Delaware
Trustee's and the Certificate Trustee's fees and expenses. The Fee Agreement
will further provide that the Delaware Trustee, the Certificate Trustee and the
Infrastructure Bank will be entitled to indemnification by the Note Issuer for,
and will be held harmless against, any loss, liability or expense incurred by
the Delaware Trustee, the Certificate Trustee and the Infrastructure Bank, as
applicable, arising from the issuance of the Certificates and any ongoing
responsibilities associated therewith (other than through such party's own
wilful misconduct, bad faith or negligence or by reason of a breach of any of
its representations or warranties set forth in the Trust Agreement).
The fiscal year of the Trust will be the calendar year.
The Trust will be formed shortly prior to the first offering of
Certificates as a special purpose Delaware business trust and, as of the date of
this Prospectus, has not carried on any business activities and has no operating
history. Because the Trust does not have any operating history, this Prospectus
does not include any financial statements or related information for the Trust.
THE INFRASTRUCTURE BANK
The Infrastructure Bank is a public body organized within the government of
the State of California and created pursuant to the Bergeson-Peace
Infrastructure and Economic Development Bank Act, codified at (S)63000 et seq.
of the California Government Code, as amended (the "ACT"). The Infrastructure
Bank is governed, and its corporate powers are exercised, by a Board of
Directors consisting of the State Director of Finance, the State Treasurer and
the State Secretary of Trade and Commerce.
Pursuant to the Act and the Statute, the Infrastructure Bank may authorize
a "special purpose trust" created by the Bank to issue "rate reduction bonds"
and to purchase with the proceeds of such "rate reduction bonds" notes issued by
the Utilities or their affiliates secured by Transition Property. For the
purposes of the Act and the Statute, the Trust will constitute a "special
purpose trust" and each Series of Certificates issued by the Trust will
constitute "rate reduction bonds" entitled to the benefit of the Statute.
Pursuant to the Act, the Infrastructure Bank has no authority to alter or
modify any term or condition related to the Transition Costs or the Transition
Property as set forth in the Financing Order, and has no authority over any
matter that is subject to the approval of the CPUC.
The Certificates do not represent an interest in or obligation of the State
of California, the Infrastructure Bank, any other governmental agency or
instrumentality or the Seller or any of its affiliates, other than the Note
Issuer. None of the Certificates, the Notes or the underlying Transition
Property will be guaranteed or insured by the State of California, the
Infrastructure Bank, the Trust or any other governmental agency or
instrumentality or by the Seller or any of its affiliates. None of such
entities will have any obligations in respect of the Certificates, except as
expressly set forth herein or in the related Prospectus Supplement.
Neither the full faith and credit nor the taxing power of the State of
California or any agency or instrumentality thereof is pledged to the
distributions of principal of, or interest on, the Certificates or the Notes or
to the payments in respect of the Transition Property.
45
<PAGE>
THE NOTE ISSUER
The Note Issuer is a special purpose, single member limited liability
company organized under the laws of the State of Delaware. The Seller is the
sole member of the Note Issuer. The principal executive office of the Note
Issuer is located at 245 Market Street, Room 424, San Francisco, California
94105. Its mailing address is Mail Code N4E, P.O. Box 770000, San Francisco, CA
94177 and its phone number is (415) 972-5467. The Note Issuer was organized for
the limited purpose of holding and servicing the Transition Property and issuing
Notes secured by the Transition Property and the other Note Collateral and
related activities, and is restricted by its organizational documents from
engaging in other activities. The assets of the Note Issuer will consist
primarily of the Transition Property and the other Note Collateral, including
capital contributed by PG&E as described under "Description of the Notes--Other
Credit Enhancement--Capital Subaccount." In addition, the Note Issuer's
organizational documents require it to operate in a manner such that it should
not be consolidated in the bankruptcy estate of PG&E in the event PG&E becomes
subject to such a proceeding.
The Note Issuer is a recently formed special purpose limited liability
company and, as of the date of this Prospectus, has not carried on any business
activities and has no operating history. Because the Note Issuer does not have
any operating history, this Prospectus does not include any income statements,
selected financial data or historical or pro forma ratio of earnings to fixed
charges for the Note Issuer, although a balance sheet will be included in any
Prospectus Supplement.
OFFICERS
The following is a list of the principal officers of the Note Issuer. All
such persons have served in the capacities set forth below since July 2, 1997.
The officers will devote such time as is necessary to the affairs of the Note
Issuer. The Note Issuer will have sufficient officers and employees to carry on
its business.
<TABLE>
<CAPTION>
NAME AGE TITLE
---- --- -----
<S> <C> <C>
Kent M. Harvey 39 President
Gabriel B. Togneri 43 Treasurer
Christopher P. Johns 37 Controller
Leslie H. Everett 46 Corporate Secretary
</TABLE>
Kent M. Harvey is President of the Note Issuer. Mr. Harvey has served as
Senior Vice President of PG&E since 1997 and Treasurer of PG&E since 1993.
Gabriel B. Togneri is Treasurer of the Note Issuer. Mr. Togneri has served
as Assistant Treasurer of PG&E since 1994.
Christopher P. Johns is Controller of the Note Issuer. Mr. Johns has
served as Vice President and Controller of PG&E since 1996 and as Vice President
and Controller of PG&E Corporation, the parent of PG&E, since 1997. Prior to
that time, Mr. Johns was an accountant with KPMG Peat Marwick from 1988.
Leslie H. Everett is Corporate Secretary of the Note Issuer. Ms. Everett
has served as Vice President of PG&E since 1996 and Corporate Secretary of PG&E
since 1993.
No compensation has been paid by the Note Issuer to any officer of the Note
Issuer since the Note Issuer was formed. The officers of the Note Issuer will
not be compensated by the Note Issuer for their services on behalf of the Note
Issuer. The Note Issuer's organizational documents limit, to the extent
permitted by Delaware law, the personal liability of each officer of the Note
Issuer to the Note Issuer for monetary damages resulting from breaches of such
officer's duty of care. The Note Issuer's organizational documents provide that
officers of the Note Issuer shall be indemnified against liabilities incurred in
46
<PAGE>
connection with their services on behalf of the Note Issuer, including
liabilities under applicable securities laws.
THE SELLER AND SERVICER
GENERAL
The Seller is engaged in the business of generating, transmitting and
distributing electric power to residential, commercial, industrial and
governmental customers within its electric service territory. PG&E's electric
service territory currently consists of approximately 70,000 square miles
throughout Northern and Central California with an estimated population of 13
million, and includes all or portions of 48 of California's 58 counties. During
1996, PG&E provided a total of 73,181 million kilowatt-hours of electricity to
4.44 million customers, including 32,235 million kilowatt-hours of electricity
provided to its approximately 4.28 million Residential Customers and Small
Commercial Customers.
As an investor-owned electric utility, the Seller is regulated by the CPUC
and the FERC.
PG&E CUSTOMER BASE AND ELECTRIC ENERGY CONSUMPTION
PG&E's customer base is divided into several categories, including the
residential and small commercial categories covered by the Statute. Residential
Customers use electricity for lighting, operating household appliances and other
domestic purposes. The primary factor influencing the number of Residential
Customers is the number of housing starts, which is a measure of the strength of
the economy. The primary factors influencing short-term energy consumption are
weather and electricity prices. Long-term factors would include the availability
of more energy efficient appliances, new energy consuming technologies and the
customer's ability to acquire these new products. Small Commercial Customers use
electricity for lighting, operating appliances and operating equipment in office
and retail settings. The primary factor influencing the number of Small
Commercial Customers is commercial employment, which is also a measure of the
strength of the economy. The factors influencing the energy consumption of a
Small Commercial Customer would include those of the Residential Customers, but
would also include the level of business activity associated with the particular
Small Commercial Customer. The table below sets forth the number of customers,
electric energy consumption and billed revenues for the two categories.
CUSTOMERS AND ENERGY CONSUMPTION
<TABLE>
<CAPTION>
AVERAGE NUMBER OF 1992 1993 1994 1995 1996
CUSTOMERS -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
Residential 3,708,374 3,748,831 3,788,044 3,825,413 3,874,223
Small Commercial 390,885 380,451 381,482 383,574 386,800
---------- ---------- ---------- ---------- ----------
Total 4,099,259 4,129,282 4,169,526 4,208,987 4,261,023
ENERGY CONSUMPTION
(GWH)
Residential 23,664 24,111 24,326 24,391 25,458
Small Commercial 6,709 6,387 6,450 6,657 6,982
---------- ---------- ---------- ---------- ----------
Total 30,373 30,498 30,776 31,049 32,439
</TABLE>
47
<PAGE>
<TABLE>
<S> <C> <C> <C> <C> <C>
BILLED
REVENUES
($000S)
Residential $2,790,605 $2,952,893 $2,980,966 $2,979,590 $3,033,612
Small Commercial 934,749 888,759 879,425 896,486 873,410
---------- ---------- ---------- ---------- ----------
Total $3,725,354 $3,841,652 $3,860,392 $3,876,076 $3,907,022
</TABLE>
FORECASTING CONSUMPTION
PG&E has developed sales and load forecasts since the company's inception.
The only things that have changed over the years have been the length of the
forecast horizon and the methods of forecasting. Sales forecasts have always had
a short horizon since they are used for rate making and budgeting purposes.
Load forecast horizons have varied over the years, depending on the lead time
necessary to construct new resources. In the early years, the horizon was as few
as four or five years, but since then it has been twelve to twenty years.
Forecasts developed in the early years used simple trending techniques.
Forecasts produced more recently have been done using more sophisticated
statistical techniques. These models produce quarterly estimates, which are
then spread to the months using recorded monthly sales data as allocation
factors.
PG&E's electric sales forecast was last updated in January 1997 and is
based on a combination of short-term and long-term forecasting models. The
short-term forecasting models are econometric models used to project sales for
the first two years after the base year. PG&E develops econometric models to
forecast electric sales for the classes of Residential Customers and small light
and power customers (which represent approximately 95% of the Small Commercial
Customers). These forecasts also will be used in calculating the FTA Charges
for any given period, in order to determine the revenue required (in the form of
FTA Payments) to meet the Expected Amortization Schedules.
The long-term models are used to forecast sales for years three through
five after the base year. They are end-use models as required by the California
Energy Commission's Common Forecasting Methodology process. Such models
explicitly forecast energy consumption by end-uses such as lighting and heating.
For the residential sector, energy consumption is the product of the total
number of households in the PG&E service area, average appliance saturations,
and average unit energy consumption by end-use. Adjustments for additional
conservation savings and appliance utilization are also accounted for in the
model.
For the small commercial sector, energy consumption is the product of floor
space (organized by building type and climate area), average end-use equipment
saturation and average unit energy consumption by end-use. Equipment
replacement rates and efficiency rates of new equipment are accounted for in the
calculations. Adjustments for additional conservation savings and equipment
utilization are also accounted for in the model.
The short- and long-term models have been in use for more than twenty
years and have undergone extensive review by the CPUC and the California Energy
Commission, respectively. Each year PG&E updates these models with the most
recent recorded data, and conducts thorough testing to ensure that model
statistics meet the highest standards possible.
PG&E utilizes DRI/McGraw Hill ("DRI") to produce economic and demographic
forecasts. The most recent DRI regional economic forecast (September 1996) was
used to drive PG&E's electric sales forecast of both the short-term and long-
term models of the residential, small light and power, and medium light and
power sectors.
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<PAGE>
The forecasted weather related drivers assume normal weather conditions.
Normal weather conditions imply a twenty year average for such weather drivers
as heating and cooling degree days.
FORECAST VARIANCE
PG&E conducts sales forecast variance analyses on a regular basis to
monitor how well forecasts track recorded consumption. This is important for
short-term resource procurement functions as well as budgeting and financial
reporting.
Since PG&E updates its forecast on an annual basis, the table below shows
annual variance for forecasts prepared for one year in the future. For example,
the annual 1992 variance is based on a forecast prepared in 1991. With the
exception of 1996, PG&E has over-forecasted the energy consumption of these
customers. The variances range from a low of 0.17% to a high of 11.05% in
absolute terms.
ANNUAL FORECAST VARIANCES
<TABLE>
<CAPTION>
RESIDENTIAL: 1992 1993 1994 1995 1996
------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C>
Forecast (1) 23,957 24,151 24,171 24,845 24,946
Actual (1) 23,664 24,111 24,326 24,391 24,458
Variance -1.24% -0.17% 0.64% -1.86% 2.01%
SMALL LIGHT AND
POWER (2)
Forecast (1) 7,306 6,796 6,697 6,458 6,464
Actual (1) 6,579 6,179 6,208 6,410 6,717
Variance -11.05% -9.99% -7.88% -0.75% 3.77%
</TABLE>
________________
(1) In GigaWatt hours.
(2) The Servicer has not historically prepared separate forecasts for the
Small Commercial Customers. However, the small light & power class of customers
represents approximately 95% of the Small Commercial Customers. Accordingly,
the Note Issuer believes that the figures relating to the small light & power
class of customers is indicative of the Servicer's forecasting history with
respect to the Small Commercial Customers.
During the last five years, no discernible trend is apparent with respect
to the historical forecast variance relating to the Residential Customers. The
variance has ranged from a 1.86% overestimate of usage to a 2.01% underestimate
of usage, with an average 0.12% overestimate estimate of usage. With respect to
the historical forecast variances relating to the small light and power class of
customers, which comprise the majority of the Small Commercial Customers, there
has been a trend towards significant improvement in forecasting in recent years.
During the early 1990's, a significant number of customers were reclassified
into classes other than the small light and power class of customers, resulting
in significant overestimates of usage relating to such class.
CREDIT POLICY; BILLING; COLLECTIONS; RESTORATION OF SERVICE
CREDIT POLICY. PG&E is obligated to provide service to all customers under
California law. PG&E relies on the information provided by the customer and its
customer information system audits to indicate whether the customer has been
previously served by PG&E.
Certain accounts are secured with deposits or guarantees to prevent losses.
The amount of the deposit reflects the potential use over a two-month period,
which is the average time period required to take billing action on past-due
billings. Since the vast majority of customers pay their bills within the
allotted time, it is not necessary to require deposits from all customers.
Specific criteria have been developed for establishing credit. These criteria
49
<PAGE>
are based on such factors as prior service, property ownership, or providing an
acceptable guarantor.
As a rule, Residential Customers may establish credit by depositing cash
equal to twice the average monthly bill or furnishing a satisfactory guarantor
Deposits or guarantees may not be required if the applicant has been a PG&E
customer during the past two years, and (a) the applicant has not had more than
two past-due billings during the last 12 consecutive months, (b) the applicant
has paid all bills for domestic service previously supplied to the applicant and
has proof of payment, or (c) the applicant's credit is otherwise established to
the satisfaction of the Company. Credit that is "established to the
satisfaction of the Company" is a broad category that includes options such as
acceptable payment records with other utilities, credit scoring, and other
factors that would establish creditworthiness.
Small Commercial Customers may establish credit by depositing cash equal to
twice the maximum monthly bills, owning substantial equity in the location to be
served, furnishing a satisfactory guarantor, or otherwise establishing credit to
the satisfaction of the Company.
Deposits or guarantees may not be required if the applicant has been a PG&E
customer during the past two years with like service, during the past 12
consecutive months of that prior service has not had more than two past due
bills, the billing for the previous service was equal to at least 50 percent of
that estimated for the new service, and the customer has paid all prior PG&E
bills.
PG&E may change its credit policies and procedures from time to time. It
is expected that any such changes would be designed to enhance PG&E's ability to
make timely recovery of amounts billed to customers.
BILLING PROCESS. PG&E bills its customers once every 27 to 33 days, with
approximately an equal number of bills being distributed each Servicer Business
Day. Any day other than a Saturday, a Sunday or a day on which the Servicer's
offices are not open for business is a "SERVICER BUSINESS DAY." For the year
ending December 31, 1996, the Company mailed out an average of 235,000 bills
daily to its various customer categories.
For accounts with potential billing errors exception reports are generated
for manual review. This review examines accounts that have abnormally high or
low bills, potential meter-reading errors and possible meter malfunctions.
PG&E may change its billing policies and procedures from time to time. It
is expected that any such changes would be designed to enhance PG&E's ability to
make timely recovery of amounts billed to customers.
COLLECTION PROCESS. PG&E receives approximately 68 percent of total bill
payments via the U.S. mail. Approximately 17 percent of bill payments are
received at local offices, and 8 percent are received at local pay stations.
PG&E receives the remainder of payments via automatic payment service,
electronic funds transfer, credit card payments and electronic data interchange.
Two days after the meter is scheduled to be read, bills are processed and
mailed to customers. Bills are due on presentation, and are considered past due
after 15 calendar days for small commercial accounts, and after 19 days for
residential accounts. Timing and collection follow-up is based on customer
type, as follows.
For Residential Customers, a reminder notice is sent to Residential
Customers if payment has not been received at the time of the second month's
billing. Eight days after the reminder notice bill is issued, a fifteen-day
notice is mailed directly to the customer if the account has a prior balance.
Ten workdays after the fifteen-day notice is sent,
50
<PAGE>
a 48-hour notice is mailed, notifying the customer that service is scheduled to
be shut off if payment is not received within 48 hours. A telephone contact, or
reasonable attempt at making telephone contact, is also required to all
residential customers prior to service shut off.
For Small Commercial Customers, thirteen Servicer Business Days after the
first billing, a seven-day notice is mailed directly to Small Commercial
Customers. A 24-hour notice, although not required, is often given to notify
Small Commercial Customers that shut-off is scheduled.
PG&E may change its collection policies and procedures from time to time.
It is expected that any such changes would be designed to enhance PG&E's ability
to make timely recovery of amounts billed to customers.
RESTORATION OF SERVICE. Once service has been shut-off for non-payment,
PG&E has the right to require the payment of all of the following charges: (i)
the total amount owing on an account including any past-due balance, the
current billing, and a credit deposit, if requested; (ii) any miscellaneous
charges associated with the reconnection of service (i.e., reconnection charges,
field collection charges, and/or returned check charges); (iii) any charges
assessed for unusual costs incidental to the termination or restoration of
service which have resulted from the customer's action or negligence; and (iv)
any unpaid closing bills from other accounts in the name of the customer of
record.
PG&E may change its restoration of service policies and procedures from
time to time. It is expected that any such changes would be designed to enhance
PG&E's ability to make timely recovery of amounts billed to customers.
LOSS AND DELINQUENCY EXPERIENCE
The following table sets forth information relating to the total billed
revenues and write-off experience of PG&E for (i) residential and (ii)
commercial, industrial and agricultural customers for each of the five preceding
years:
TOTAL GAS & ELECTRIC BILLED REVENUES
<TABLE>
<CAPTION>
1992 1993 1994 1995 1996
-------------- -------------- -------------- -------------- --------------
<S> <C> <C> <C> <C> <C>
RESIDENTIAL $3,883,024,170 $4,105,456,235 $4,251,147,446 $4,186,692,646 $4,144,856,090
COMMERCIAL, INDUSTRIAL & 5,865,106,178 5,787,993,498 5,484,670,968 5,458,124,905 5,089,201,197
AGRICULTURAL (1) -------------- -------------- -------------- -------------- --------------
TOTAL $9,748,130,348 $9,893,449,733 $9,735,818,415 $9,644,817,552 $9,234,057,286
NET GAS AND ELECTRIC WRITE-OFFS (2)
<CAPTION>
1992 1993 1994 1995 1996
----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C>
RESIDENTIAL $20,235,760 $22,362,116 $25,064,904 $33,358,262 $26,726,988
COMMERCIAL, INDUSTRIAL &
AGRICULTURAL (1) 7,483,259 7,027,293 9,078,783 10,393,267 7,524,792
----------- ----------- ----------- ----------- -----------
TOTAL $27,719,019 $29,389,409 $34,143,687 $43,751,529 $34,251,780
NET WRITE-OFFS AS A PERCENTAGE OF BILLED REVENUE (2)
<CAPTION>
1992 1993 1994 1995 1996
----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C>
RESIDENTIAL 0.52% 0.54% 0.59% 0.80% 0.64%
COMMERCIAL, INDUSTRIAL &
AGRICULTURAL (1) 0.13% 0.12% 0.17% 0.19% 0.15%
---- ---- ---- ---- ----
TOTAL 0.29% 0.30% 0.35% 0.46% 0.37%
</TABLE>
51
<PAGE>
- ----------------
(1) PG&E has not historically maintained separate information regarding
write-offs for the Small Commercial Customers. Revenues for Small Commercial
Customers constituted approximately 20% of revenues for the commercial,
industrial and agricultural class of electricity consumers in 1996.
(2) Net write-offs include any amounts recovered by PG&E from deposits,
bankruptcy proceedings and payments received after an account has been closed.
Slight historical trends towards increased net write-offs are apparent with
respect to both the Residential Customers and the commercial, industrial and
agricultural users. However, such net write-offs continue to be statistically
insignificant.
DELINQUENCIES
The following table sets forth information relating to the delinquency
experience of PG&E for (i) residential and (ii) commercial, industrial and
agricultural customers for each of the five preceding years:
RESIDENTIAL AND COMMERCIAL DELINQUENCY DATA/(1)/
<TABLE>
<CAPTION>
1992 1993 1994 1995 1996
----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C>
RESIDENTIAL:
PERCENT OF BILLED REVENUE 62.0% 61.0% 58.0% 56.0% 66.0%
COLLECTED WITHIN: 72.2 72.1 69.1 71.8 75.8
30 DAYS 92.5 92.2 90.4 90.2 92.1
60 DAYS
90 DAYS
<CAPTION>
1992 1993 1994 1995 1996
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
COMMERCIAL, INDUSTRIAL &
AGRICULTURAL(2):
PERCENT OF BILLED REVENUE
COLLECTED WITHIN:
30 DAYS 79.0% 77.0% 75.0% 76.0% 80.0%
60 DAYS 82.7 81.1 81.1 82.0 84.3
90 DAYS 97.6 97.2 96.5 97.0 97.9
</TABLE>
________________
(1) Data shows delinquency statistics for combined gas and electric
revenues and collections.
(2) PG&E has not historically maintained separate information relating to
delinquencies for the Small Commercial Customers. Revenues for Small Commercial
Customers constituted approximately 20% of the commercial, industrial and
agricultural class of electricity consumers in 1996.
No discernable trends are apparent with respect to PG&E's delinquency
experiences with respect to the Residential Customers and the commercial,
industrial and agricultural customers. The Note Issuer does not believe that
the delinquency experience with respect to the FTA Payments will differ
substantially from the approximate rates indicated above.
52
<PAGE>
SERVICING
SERVICING PROCEDURES
GENERAL. The Servicer, as agent for the Note Issuer, will manage, service
and administer, and make collections in respect of, the Transition Property
pursuant to the Servicing Agreement between the Servicer and the Note Issuer.
Except to the extent that alternative energy service providers elect to engage
in consolidated billing (as described herein under "Risk Factors--Potential
Servicing Issues--Reliance on Aggregators and Other Suppliers"), the Servicer's
duties will include calculation and billing of all amounts based on the FTA
Charges, receipt and posting of all FTA Payments, responding to inquiries of
Customers and the CPUC with respect to the Transition Property and the FTA
Charges, obtaining usage calculations, accounting for collections and furnishing
monthly, quarterly and annual statements to the Note Issuer, the Note Trustee
and the Certificate Trustee and taking action in connection with periodic
revisions to the FTA Charges as described below.
Each FTA Charge will be expressed as an amount per kilowatt hour of
electricity usage by the applicable Customer, regardless of whether the Customer
receives its electricity from the Servicer or from another electricity provider.
The Servicer expects the applicable FTA Charge to be separately identified on
each Customer's bill, with an aggregate amount to be paid to the Servicer for
all services provided by the Servicer. Bills are sent to Customers every 27 to
33 days.
Any amounts collected by the Servicer that represent partial payments of
the total amount billed will be proportionately allocated between the Note
Issuer and PG&E based on the portion of the amount billed which is based on the
applicable FTA Charge and the total charges due to PG&E. If such amounts are
billed and collected for an alternative energy service provider pursuant to a
consolidated billing arrangement, the total charges due to the alternative
energy service provider will also be included in the proportionate allocation of
any partial payment.
SERVICING STANDARDS AND COVENANTS
The Servicing Agreement will require the Servicer, in servicing and
administering the Transition Property, to employ or cause to be employed
procedures and exercise the same care it customarily employs and exercises in
servicing and administering bill collections for its own account.
Consistent with the foregoing, the Servicer may in its own discretion waive
any late payment charge or any other fee or charge relating to delinquent
payments, if any, and may waive, vary or modify any terms of payment of any
amounts payable by a Customer, in each case, if such waiver or action (a) would
be in accordance with the Servicer's customary practices or those of any
successor Servicer with respect to comparable assets that it services for
itself, (b) would not materially adversely affect the Certificateholders and (c)
would comply with applicable law.
In the Servicing Agreement, the Servicer will covenant that, in servicing
the Transition Property it will: (a) manage, service, administer and make
collections in respect of the Transition Property with reasonable care and in
accordance with applicable law, including all applicable guidelines of the CPUC,
using the same degree of care and diligence that the Servicer exercises with
respect to bill collections for its own account; (b) follow customary standards,
policies and procedures for the industry in performing its duties as Servicer;
(c) use all reasonable efforts, consistent with its customary servicing
procedures, to enforce, and maintain rights in respect of, the Transition
Property; (d) comply with all laws applicable to and binding on it relating to
the Transition Property; and (e) submit True-Up Mechanism Advice Letters to the
CPUC seeking adjustments to the FTA Charges as described herein.
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<PAGE>
In the event of a breach by the Servicer of any of these covenants, the
Servicer will indemnify, defend and hold harmless the Note Issuer, the Trust,
the Noteholders, the Note Trustee, the Certificate Trustee, the Delaware
Trustee, the Certificateholders and the Infrastructure Bank against any costs,
expenses, losses, claims, damages and liabilities incurred as a result thereof.
REMITTANCES TO COLLECTION ACCOUNT
Periodically, the Servicer will prepare a forecast of the percentages of
amounts billed in a particular month that are expected to be received during
each of the following six months (the "COLLECTIONS CURVE"). For so long as (a)
no Servicer Default shall have occurred and be continuing and (b) the Rating
Agency Condition shall have been satisfied (and any conditions or limitations
imposed by the Rating Agencies in connection therewith are complied with), the
Servicer is required to remit FTA Payments expected to have been received during
the preceding Billing Period, based on the Collections Curve then in effect, to
the Collection Account on or before the twentieth day of each calendar month
(or, if such twentieth day is not a Certificate Business Day, the Certificate
Business Day immediately following such twentieth day). The sum of the amounts
remitted with respect to a Billing Period during the six months following such
Billing Period based on the Collections Curve is referred to as the "ESTIMATED
FTA PAYMENTS" herein. Pending remittance to the Collection Account, FTA
Payments may be invested by the Servicer at its own risk and for its own
benefit, and will not be segregated from funds of the Servicer. If any of the
conditions described above are not satisfied, the Servicer will remit within two
Servicer Business Days of receipt thereof to the Collection Account all
Estimated FTA Payments. The date on which FTA Payments received by the Servicer
with respect to the FTA Charges are required to be deposited in the Collection
Account is referred to herein as the "REMITTANCE DATE."
On or prior to the Remittance Date in the seventh month following a monthly
Billing Period, the Servicer will compare actual FTA Payments received with
respect to that Billing Period (the "ACTUAL FTA PAYMENTS") to the Estimated FTA
Payments for that Billing Period previously remitted to the Collection Account.
If Estimated FTA Payments remitted with respect to a Billing Period exceed
Actual FTA Payments attributable to such Billing Period (such excess, an "EXCESS
REMITTANCE"), the Servicer shall be entitled to either (a) reduce the amount
which the Servicer remits to the Collection Account on such Remittance Date by
the amount of such Excess Remittance, the amount of such reduction becoming the
property of the Servicer or (b) immediately be paid from the Collection Account
or any subaccount therein the amount of such Excess Remittance, such payment
becoming the property of the Servicer. If Estimated FTA Payments remitted with
respect to a Billing Period are less than Actual FTA Payments attributable to
such Billing Period (such deficiency, a "REMITTANCE SHORTFALL"), the amount
which the Servicer remits to the Collection Account on such Remittance Date will
be increased by the amount of such Remittance Shortfall, such increase coming
from the Servicer's own funds. The Estimated FTA Payments calculated for any
Remittance Date shall not be affected by any Excess Remittance or Remittance
Shortfall which modifies the actual amount remitted by the Servicer on such
Remittance Date.
NO SERVICER ADVANCES
The Servicer will not make any advances of interest or principal on the
Notes.
54
<PAGE>
SERVICING COMPENSATION
The Servicer will be entitled to receive the Servicing Fee for each
calendar quarter, in an amount equal to one-fourth the percent per annum
specified in the related Prospectus Supplement of the then outstanding principal
amount of the Notes. The Servicing Fee (together with any portion of the
Servicing Fee that remains unpaid from prior Payment Dates) will be paid solely
to the extent funds are available therefor as described under "Description of
the Notes--Allocations; Payments." The Servicing Fee will be paid prior to the
distribution of any amounts in respect of interest on and principal of the
Notes. The Servicer will be entitled to retain as additional compensation net
investment income on FTA Payments received by the Servicer prior to remittance
thereof to the Collection Account and the portion of late fees, if any, paid by
Customers relating to the FTA Payments.
AGGREGATORS AND OTHER SUPPLIERS
As part of the deregulation of the California electric industry described
elsewhere herein, there will be an unbundling of generation, transmission,
distribution and billing services. A decision of the CPUC allows alternative
energy service providers ("ESPS") to elect to present a consolidated bill to
their retail customers covering amounts owed to the ESP for electricity, amounts
owed to the Utilities for distribution and the applicable FTA Charge. Any ESP
who elects consolidated billing, including monthly amounts with respect to the
FTA Charges, will be responsible for paying the Servicer periodic amounts
payable by customers of the ESP regardless of the ESP's ability to collect the
FTA Charges form its customers. Neither the Seller nor the Servicer will pay
any shortfalls resulting from the failure of any ESPs to forward FTA Payments to
PG&E, as Servicer, which may result in delays in distributions to
Certificateholders. See "Risk Factors--Potential Servicing Issues--Reliance on
Aggregators and Other Suppliers" herein.
SERVICER REPRESENTATIONS AND WARRANTIES
In the Servicing Agreement, the Servicer will make representations and
warranties to the Note Issuer to the effect, among other things, that: (a) the
Servicer is a corporation duly organized and in good standing under the laws of
the State of California, with power and authority to own its properties and
conduct its business as currently owned or conducted and to execute, deliver and
carry out the terms of the Servicing Agreement; (b) the execution, delivery and
carrying out of the Servicing Agreement have been duly authorized by the
Servicer by all necessary corporate action; (c) the Servicing Agreement
constitutes a legal, valid and binding obligation of the Servicer, enforceable
against the Servicer in accordance with its terms; (d) the consummation of the
transactions contemplated by the Servicing Agreement does not conflict with the
Servicer's articles of incorporation or bylaws or any agreement to which the
Servicer is a party or bound, result in the creation or imposition of any lien
upon the Servicer's properties or violate any law or any order, rule or
regulation applicable to the Servicer; (e) the Servicer has all licenses
necessary for it to perform its obligations under the Servicing Agreement; (f)
no governmental approvals, authorizations or filings are required for the
Servicer to execute, deliver and perform its obligations under the Servicing
Agreement except those which have previously been obtained or made; and (g)
except as disclosed to the Note Issuer, no court or administrative proceeding or
investigation is pending or, to the Servicer's knowledge, threatened (i)
asserting the invalidity of, or seeking to prevent the consummation of the
transactions contemplated by, the Servicing Agreement or (ii) seeking a
determination that might materially and adversely affect the performance by the
Servicer of its obligations thereunder.
In the event of a breach by the Servicer of any of its representations and
warranties described in the preceding paragraph, the Servicer will indemnify,
defend and hold harmless the Note Issuer, the Trust, the Noteholders, the Note
Trustee, the Certificate Trustee, the Delaware Trustee, the Certificateholders
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and the Infrastructure Bank against any costs, expenses, losses, claims, damages
and liabilities incurred as a result thereof.
STATEMENTS BY SERVICER
On or before each Remittance Date, the Servicer will prepare and furnish to
the Note Trustee, the Certificate Trustee, the Infrastructure Bank and the Note
Issuer a statement for the applicable Billing Periods (the "MONTHLY SERVICER'S
CERTIFICATE") setting forth the aggregate amount remitted, the FTA Collections
and the Excess Remittance or the Remittance Shortfall. In addition, the
Servicer will prepare, and the Note Trustee will furnish to the Noteholders on
each Payment Date the Quarterly Servicer's Certificate described under
"Description of the Notes--Reports to Noteholders." The Servicer will also
prepare and the Certificate Trustee will furnish to the Certificateholders on
each Payment Date the report described under "Description of the Certificates--
Reports to Certificateholders" herein.
EVIDENCE AS TO COMPLIANCE
The Servicing Agreement will provide that a firm of independent public
accountants will furnish to the Note Issuer, the Note Trustee and the
Certificate Trustee on or before January 31 of each year, beginning January 31,
1998, a statement as to compliance by the Servicer during the preceding twelve
months ended December 31 with certain standards relating to the servicing of the
Transition Property. This report (the "ANNUAL ACCOUNTANT'S REPORT") shall state
that such firm has performed certain procedures in connection with the
Servicer's compliance with the servicing procedures of the Servicing Agreement,
identifying the results of such procedures and including any exceptions noted.
The Annual Accountant's Report will also indicate that the accounting firm
providing such report is independent of the Servicer within the meaning of the
Code of Professional Ethics of the American Institute of Certified Public
Accountants.
The Servicing Agreement will also provide for delivery to the Note Issuer,
the Infrastructure Bank, the Note Trustee and the Certificate Trustee, on or
before January 31 of each year, commencing January 31, 1998, of a certificate
signed by an officer of the Servicer stating that the Servicer has fulfilled its
obligations under the Servicing Agreement throughout the preceding twelve months
ended December 31 (or in the case of the first such certificate, the period from
the Closing Date to December 31, 1997) or, if there has been a default in the
fulfillment of any such obligation, describing each such default. The Servicer
has agreed to give the Note Issuer, the Infrastructure Bank, the Note Trustee
and the Certificate Trustee notice of certain Servicer Defaults under the
Servicing Agreement.
Copies of such statements and certificates may be obtained by
Certificateholders by a request in writing addressed to the Certificate Trustee.
CERTAIN MATTERS REGARDING THE SERVICER
The Servicing Agreement will provide that PG&E may not resign from its
obligations and duties as Servicer thereunder, except upon either (a) a
determination that PG&E's performance of such duties is no longer permissible
under applicable law or (b) satisfaction of the Rating Agency Condition, consent
of the CPUC and an arrangement with a successor servicer which provides that
there is no increase in the Servicing Fee. No such resignation will become
effective until a successor Servicer has assumed PG&E's servicing obligations
and duties under the Servicing Agreement.
The Servicing Agreement will further provide that neither the Servicer nor
any of its directors, officers, employees, and agents will be under any
liability
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to the Note Issuer, the Note Trustee, the Infrastructure Bank, the Trust, the
Noteholders, the Delaware Trustee, the Certificate Trustee, the
Certificateholders or any other person, except as provided under the Servicing
Agreement, for taking any action or for refraining from taking any action
pursuant to the Servicing Agreement, or for errors in judgment; provided,
however, that neither the Servicer nor any such person will be protected against
any liability that would otherwise be imposed by reason of willful misconduct,
bad faith or gross negligence in the performance of duties or by reason of
reckless disregard of obligations and duties thereunder. In addition, the
Servicing Agreement will provide that the Servicer is under no obligation to
appear in, prosecute, or defend any legal action that is not incidental to its
servicing responsibilities under the Servicing Agreement and that, in its
opinion, may cause it to incur any expense or liability.
Under the circumstances specified in the Servicing Agreement, any entity
into which the Servicer may be merged or consolidated, or any entity resulting
from any merger or consolidation to which the Servicer is a party, or any entity
succeeding to the business of the Servicer or, with respect to its obligations
as Servicer, which corporation or other entity in each of the foregoing cases
assumes the obligations of the Servicer, will be the successor of the Servicer
under the Servicing Agreement.
SERVICER DEFAULTS
"SERVICER DEFAULTS" under the Servicing Agreement will include (a) any
failure by the Servicer to make any required deposit into the Collection
Account, which failure continues unremedied for three Servicer Business Days
after written notice from the Note Issuer is received by the Servicer or after
discovery by the Servicer; (b) any failure by the Servicer or the Seller, as the
case may be, duly to observe or perform in any material respect any other
covenant or agreement in the Servicing Agreement, the Sale Agreement or any
other Basic Document to which it is a party, which failure materially and
adversely affects the rights of Noteholders and which continues unremedied for
60 days after the giving of notice of such failure (i) to the Servicer by the
Note Issuer or the Note Trustee or (ii) to the Servicer by holders of Notes
evidencing not less than 25 percent in principal amount of the outstanding Notes
of all Series; (c) any representation or warranty made by the Servicer in the
Servicing Agreement shall prove to have been incorrect when made, which has a
material adverse effect on the Note Issuer or the Certificateholders and which
material adverse effect continues unremedied for a period of 60 days after the
giving of notice to the Servicer by the Note Issuer or the Note Trustee; and (d)
certain events of insolvency, readjustment of debt, marshaling of assets and
liabilities, or similar proceedings with respect to the Servicer or the Seller
and certain actions by the Servicer or the Seller indicating its insolvency,
reorganization pursuant to bankruptcy proceedings, or inability to pay its
obligations.
RIGHTS UPON SERVICER DEFAULT
As long as a Servicer Default under the Servicing Agreement remains
unremedied, either the Note Trustee or holders of Notes evidencing not less than
25 percent in principal amount of then outstanding Notes of all Series may
terminate all the rights and obligations of the Servicer (other than the
Servicer's indemnity obligation) under the Servicing Agreement, whereupon a
successor servicer appointed by the Note Trustee will succeed to all the
responsibilities, duties and liabilities of the Servicer under the Servicing
Agreement and will be entitled to similar compensation arrangements. In
addition, upon a Servicer Default, each of the following shall be entitled to
apply to the CPUC for sequestration and payment of revenues arising with respect
to the Transition Property: (1) the Certificateholders and the Certificate
Trustee as beneficiary of any statutory lien permitted by the PU Code; (2) the
Note Issuer or its assignees; or (3) pledgees or transferees, including
transferees under PU Code (S) 844, of the Transition Property. If, however, a
bankruptcy trustee or similar official has been appointed for the Servicer, and
no Servicer Default other than such appointment has occurred, such trustee or
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official may have the power to prevent the Note Trustee or the Noteholders from
effecting a transfer of servicing. The Note Trustee may appoint, or petition a
court of competent jurisdiction for the appointment of, a successor servicer
which satisfies criteria specified by the Rating Agencies. The Note Trustee may
make such arrangements for compensation to be paid, which in no event may be
greater than the servicing compensation to the Servicer under the Servicing
Agreement.
WAIVER OF PAST DEFAULTS
Holders of Notes evidencing at least a majority in principal amount of the
then outstanding Notes of all Series, on behalf of all Noteholders, may waive
any default by the Servicer in the performance of its obligations under the
Servicing Agreement and its consequences, except a default in making any
required deposits to the Collection Account in accordance with the Servicing
Agreement. The Servicing Agreement provides that no such waiver will impair the
Noteholders' rights with respect to subsequent defaults.
AMENDMENT
The Servicing Agreement may be amended by the parties thereto, without the
consent of the Noteholders (or, accordingly, the Certificateholders), but with
the consent of the Note Trustee, for the purpose of adding any provisions to or
changing in any manner or eliminating any of the provisions of that agreement or
of modifying in any manner the rights of the Noteholders (or, accordingly, the
Certificateholders), provided that such action will not, as certified in a
certificate of an officer of the Servicer delivered to the Note Trustee and the
Note Issuer, materially and adversely affect the interest of any Noteholder (or,
accordingly, any Certificateholder). The Servicing Agreement may also be
amended by the Servicer and the Note Issuer with the consent of the Note Trustee
and the holders of Notes evidencing at least a majority in principal amount of
the then outstanding Notes of all Series and Classes for the purpose of adding
any provisions to or changing in any manner or eliminating any of the provisions
of such agreement or of modifying in any manner the rights of the Noteholders or
the Certificateholders; provided, however, that no such amendment may (i)
-------- -------
increase or reduce in any manner the amount of, or accelerate or delay the
timing of, FTA Collections or (ii) reduce the aforesaid percentage of the Notes
the holders of which are required to consent to any such amendment, without the
consent of the holders of all the outstanding Notes.
TERMINATION
The obligations of the Servicer and the Note Issuer pursuant to the
Servicing Agreement will terminate upon the payment to the Noteholders and
corresponding distribution to the Certificateholders of all amounts required to
be paid or distributed to them pursuant to the Servicing Agreement, the Notes,
the Note Indenture, the Certificates and the Trust Agreement.
DESCRIPTION OF THE NOTES
The Notes of any Class will be issued by the Note Issuer to the Trust (as
such, the "NOTEHOLDER") pursuant to the terms of an Indenture (the "NOTE
INDENTURE") between the Note Issuer and the Note Trustee, in a principal amount
equal to the initial aggregate principal amount of the related Class of
Certificates. The following summary describes the material terms and provisions
of the Note Indenture. The particular terms of the Notes of any Class will be
established in a supplement to the Note Indenture and the material terms thereof
will be described in the Prospectus Supplement for the related Series of
Certificates. This summary does not purport to be complete and is subject to,
and is qualified in its entirety by reference to, the terms and provisions of
the Note Indenture and related supplements thereto, forms of which are filed as
exhibits to the Registration Statement.
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GENERAL
The Notes may be issued in one or more Series, any one or more of which may
be comprised of one or more Classes. All Notes of the same Series will be
identical in all respects except for the denominations thereof, unless such
Series is comprised of more than one Class, in which case all Notes of the same
Class will be identical in all respects except for the denominations thereof.
The Prospectus Supplement for a Series of Certificates will describe the
following terms of the related Series of Notes and, if applicable, the Classes
thereof: (a) the designation of the Series and, if applicable, the Classes
thereof, (b) the principal amount, (c) the annual rate at which interest accrues
(the "NOTE INTEREST RATE"), (d) the Payment Dates, (e) the scheduled maturity
date (the "SCHEDULED MATURITY DATE"), (f) the final termination date of the
Series (the "FINAL MATURITY DATE"), (g) the issuance date of the Series (the
"SERIES ISSUANCE DATE"), (h) the place or places for the payment of principal,
(i) the authorized denominations, (j) the provisions for optional redemption by
the Note Issuer, (k) the Expected Amortization Schedule for principal of such
Series and, if applicable, the Classes thereof, (l) the terms, if any, on which
any Series or Class of Notes will be subordinated to any other Series or Class
of Notes, (m) the FTA Charges as of the date of issuance of such Series of
Notes, and the portion of the FTA Charges attributable to such Series or Class
of Notes and (n) any other terms of such Class that are not inconsistent with
the provisions of the Notes and that will not result in any Rating Agency
reducing or withdrawing its then current rating of any outstanding Class of
Notes or Certificates (the notification in writing by each Rating Agency to the
Seller, the Servicer, the Note Trustee and the Note Issuer that any action will
not result in such a reduction or withdrawal is referred to herein as the
"RATING AGENCY CONDITION").
SECURITY
To secure the payment of principal of and interest on the Notes, the Note
Issuer will grant to the Note Trustee a security interest in all of the Note
Issuer's right, title and interest in and to (a) all of the Transition Property
and all proceeds thereof, (b) the Sale Agreement, (c) the Servicing Agreement,
(d) the Collection Account and all amounts or investment property on deposit
therein or credited thereto from time to time, (e) all other property of
whatever kind owned from time to time by the Note Issuer, which such other
property is expected to be relatively small, (f) all present and future claims,
demands, causes and choses in action in respect of any or all of the foregoing
and all payments on or under and (g) all proceeds in respect of any or all of
the foregoing; provided, however, that (1) the cash contributed to the Note
Issuer by the Seller which is not held in the Capital Subaccount, including cash
that has been released to the Note Issuer following retirement of a related
Series of Certificates, (2) net investment earnings which have been released to
the Note Issuer by the Note Trustee pursuant to the terms of the Indenture and
(3) the Overcollateralization Amount with respect to a Series of Certificates
that has been released to the Note Issuer following retirement of such Series
will not be covered by the foregoing security interest. The foregoing assets to
which the Note Issuer will grant the Note Trustee a security interest are
referred to collectively as the "NOTE COLLATERAL" herein.
COLLECTION ACCOUNT
The Note Issuer will establish, in the name of the Note Trustee, a
segregated identifiable account (the "COLLECTION ACCOUNT") with an Eligible
Institution. The Collection Account will be held by the Note Trustee for the
benefit of the Noteholders. The Collection Account will consist of four
subaccounts: a general subaccount (the "GENERAL SUBACCOUNT"), a reserve
subaccount (the "RESERVE SUBACCOUNT"), a subaccount for the
Overcollateralization Amount (the "OVERCOLLATERALIZATION SUBACCOUNT") and a
capital subaccount (the "CAPITAL SUBACCOUNT"). All amounts in the Collection
Account not allocated to any other subaccount will be allocated to the General
Subaccount. Unless the
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context indicates otherwise, references herein to the Collection Account include
each of the subaccounts contained therein.
An "ELIGIBLE INSTITUTION" means (a) the corporate trust department of the
Note Trustee or (b) a depository institution organized under the laws of the
United States of America or any one of the states thereof or the District of
Columbia (or any domestic branch of a foreign bank), which (i) has either (A) a
long-term unsecured debt rating of "A" by S&P and Moody's or (B) a certificate
of deposit rating of "A-1" by S&P and "P-1" by Moody's, or any other long-term,
short-term or certificate of deposit rating acceptable to the Rating Agencies
and (ii) whose deposits are insured by the Federal Deposit Insurance Corporation
(the "FDIC").
Funds in the Collection Account may be invested in any of the following:
(a) direct obligations of, or obligations fully and unconditionally guaranteed
as to timely payment by, the United States of America, (b) demand deposits, time
deposits, certificates of deposit or bankers' acceptances of certain depository
institutions or trust companies, (c) commercial paper having, at the time of
investment, a rating in the highest rating category from each Rating Agency, (d)
money market funds which have the highest rating from each Rating Agency, (e)
demand deposits, time deposits and certificates of deposit which are fully
insured by the FDIC, (f) repurchase obligations with respect to any security
that is a direct obligation of, or fully guaranteed by, the United States of
America or certain agencies or instrumentalities thereof, entered into with
certain depository institutions or trust companies, or (g) any other investment
permitted by each Rating Agency (collectively, the "ELIGIBLE INVESTMENTS"), in
each case which mature on or before the Certificate Business Day preceding the
next Payment Date. The Note Trustee and the Certificate Trustee will have
access to the Collection Account for the purpose of making deposits in and
withdrawals from the Collection Account in accordance with the Indenture.
The Servicer will remit to the Collection Account, on each Remittance Date,
FTA Payments expected to have been received during the preceding Billing Period,
based on the Collections Curve, modified by the Excess Remittance or Remittance
Shortfall, if any, as described under "Servicing--Remittances to Collection
Account" herein.
INTEREST AND PRINCIPAL
Interest will accrue on the principal balance of Notes of a Class of Notes
at the per annum rate either specified in or determined in the manner specified
in the related Prospectus Supplement and will be payable on the Payment Dates
specified in the related Prospectus Supplement. FTA Collections and, if
necessary, the relatively small equity contributed to the Note Issuer by PG&E,
will be used to make interest payments to the Noteholders of each Class on each
Payment Date with respect thereto.
Principal of the Notes of each Class will be payable in the amounts and on
the Payment Dates specified in the related Prospectus Supplement, but only to
the extent that amounts in the Collection Account are available therefor, and
subject to the other limitations described below. See "--Allocations; Payments"
herein. Each Prospectus Supplement will set forth the Expected Amortization
Schedule for the related Series of Notes and, if applicable, the Classes of such
Series. On any Payment Date, the Note Issuer will make payments on the Notes
only until the outstanding principal balances thereof have been reduced to the
principal balances specified in the applicable Expected Amortization Schedule
for such Distribution Date. Any FTA Collections in excess of amounts payable as
(a) expenses of the Note Issuer and the Trust, (b) payments of interest on and
principal of the Notes, (c) allocations to the Overcollateralization Subaccount
and (d) allocations to the Capital Subaccount (all as described herein under
"Description of the Notes--Allocations; Payments" herein) will be retained by
the Note Trustee in the Reserve Subaccount for payment on subsequent Payment
Dates. However, if
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insufficient FTA Collections are received with respect to any Payment Date, and
amounts in the Collection Account are not sufficient to make up the shortfall,
principal of any Class of Notes may be payable later than expected as described
herein. See "Risk Factors--Risks of the Transition Property" and "--Uncertain
Distribution Amounts and Weighted Average Life" herein. The entire unpaid
principal amount of the Notes of a Class will be due and payable on the date on
which a Note Event of Default has occurred and is continuing with respect to
such Class, if the holders of a majority in principal amount of the Notes of all
Series then outstanding have declared the Notes to be immediately due and
payable. See "--Note Events of Default; Rights Upon Note Event of Default"
herein.
Unless the context requires otherwise, all references in this Prospectus to
principal of the Notes of a Series includes any premium that might be payable
thereon if Notes of such Series are redeemed, as described in the related
Prospectus Supplement.
OPTIONAL REDEMPTION
The Note Issuer may redeem, at its option, any Series of Notes and
accordingly cause the Trust to redeem the related Series of Certificates if the
outstanding principal balance of the Series of Notes has been reduced to less
than five percent of the initial principal balance thereof. Unless otherwise
specified in the related Prospectus Supplement, notice of such redemption will
be given by the Note Issuer to each holder of Notes to be redeemed by first-
class mail, postage prepaid, mailed not less than five days nor more than 25
days prior to the date of redemption.
OVERCOLLATERALIZATION AMOUNT
The Financing Order and Advice Letters give the Seller (or its assignee)
the right to recover from Customers an amount equal to the aggregate Transition
Costs together with designated amounts included therewith, including without
limitation amounts necessary to pay principal of and interest on each Series of
Notes at the applicable Note Interest Rate and all related fees and expenses,
and an additional amount (for any Series, the "OVERCOLLATERALIZATION AMOUNT")
that will be specified in the related Prospectus Supplement. The
Overcollateralization Amount will be collected ratably over the life of the
Certificates. The portion of FTA Collections relating to the
Overcollateralization Amount received with respect to any Payment Date is
referred to as the "QUARTERLY OVERCOLLATERALIZATION COLLECTION" herein.
On each Payment Date, all FTA Collections will be applied first to pay or
provide for fees and expenses and interest on each Series of Notes at the
applicable Note Interest Rate. All other FTA Collections will be applied to pay
or provide for principal of the Notes, with a corresponding reduction in the
aggregate recoverable amount payable with respect to the FTA Charges. See "--
Allocations; Payments" herein. On any Payment Date, an amount equal to the
lesser of the Quarterly Overcollateralization Collection and amounts remaining
after payment of scheduled amounts due on the Notes will be deposited in the
Overcollateralization Subaccount. Amounts in the Overcollateralization
Subaccount will be invested in Eligible Investments, and the Note Issuer will be
entitled to earnings thereon, subject to the limitations described under "--
Allocations; Payments" herein. Amounts in the Overcollateralization Subaccount
are intended to cover any shortfall in FTA Collections that might otherwise
occur on any Payment Date or at the last Scheduled Maturity Date for any Series
or Class of Notes. Any amounts remaining in the Overcollateralization
Subaccount with respect to a particular Series of Notes in excess of the amounts
required to make distributions on the related Series of Certificates in full at
the Termination Date will be returned to the Note Issuer, which may distribute
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such amounts to its members under the circumstances described under "--Certain
Covenants of the Note Issuer."
OTHER CREDIT ENHANCEMENT
CAPITAL SUBACCOUNT. Upon the issuance of each Series of Notes, the Seller
will contribute capital to the Note Issuer in an amount specified in each
Prospectus Supplement, which will equal 0.50% of the initial principal amount of
each such Series of Notes. Such amount, less $100,000 in the aggregate for all
Series of Notes (with respect to each Series, the "REQUIRED CAPITAL LEVEL"),
will be deposited into the Capital Subaccount. On each Payment Date, the Note
Trustee will draw on amounts in the Capital Subaccount, if any, to the extent
amounts available in the General Subaccount, the Overcollateralization
Subaccount and the Reserve Subaccount are insufficient to make scheduled
payments on the Notes and pay expenses of the Note Issuer and the Trust.
Deposits to the Capital Subaccount will be made as described under "Description
of the Notes--Allocations; Payments" herein.
RESERVE SUBACCOUNT. FTA Collections available with respect to any Payment
Date in excess of amounts payable as expenses of the Note Issuer and the Trust,
as payments of interest and principal on the Notes, as allocations to the
Overcollateralization Subaccount and as allocations to the Capital Subaccount
(all as described under "--Allocations; Payments" herein), will be allocated to
the Reserve Subaccount. On each Payment Date, the Note Trustee will draw on
amounts in the Reserve Subaccount, if any, to the extent amounts available in
the General Subaccount are insufficient to make scheduled payments on the Notes
and pay expenses of the Note Issuer and the Trust. Amounts in the Reserve
Subaccount will be invested in Eligible Investments, and the Note Issuer will be
entitled to earnings thereon, subject to the limitations described under "--
Allocations; Payments" herein.
OTHER. For any Class of Notes, credit enhancement in addition to the true-
up adjustment mechanism, the Overcollateralization Amount, the Reserve
Subaccount and the Capital Subaccount may be provided with respect thereto. The
amounts and types of credit enhancement, and the provider of any credit
enhancement, if any, with respect to each Class of Notes will be described in
the related Prospectus Supplement. If specified in the related Prospectus
Supplement, credit enhancement for a Class of Notes may cover one or more other
Classes of Notes.
If any such additional credit enhancement is provided with respect to a
Class of Notes offered hereby, the related Prospectus Supplement will include a
description of (a) the amount payable under such credit enhancement, (b) any
conditions to payment thereunder not otherwise described herein, (c) the
conditions (if any) under which the amount payable under such credit enhancement
may be reduced and under which such credit enhancement may be terminated or
replaced, (d) the priority of reimbursement to the provider of the credit
enhancement of amounts paid pursuant to the credit enhancement and (e) any
material provisions of any applicable agreement relating to such credit
enhancement. Additionally, in certain cases, the related Prospectus Supplement
may set forth certain information with respect to the provider of any third-
party credit enhancement, including (i) a brief description of its principal
business activities, (ii) its principal place of business, place of
incorporation and the jurisdiction under which it is chartered or licensed to do
business, (iii) if applicable, the identity of regulatory agencies which
exercise primary jurisdiction over the conduct of its business and (iv) its
total assets, and its stockholders' equity or policyholders' surplus, if
applicable, as of a date specified in the related Prospectus Supplement.
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The presence of any such additional credit enhancement is intended to
enhance the likelihood of receipt by the credit enhanced Noteholders of the full
amount of principal and interest due thereon in a timely manner and to decrease
the likelihood that such Noteholders will experience losses or delays in
payment. Any such additional credit enhancement for a Class of Notes will not
provide protection against all risks of loss and will not guarantee repayment of
the entire principal and interest thereon. If losses occur which exceed the
amount covered by any credit enhancement or which are not covered by any credit
enhancement, Noteholders will bear their allocable share of deficiencies. In
addition, if a form of additional credit enhancement covers more than one Class
of Notes, Noteholders of any such Class will be subject to the risk that such
credit enhancement will be exhausted by the claims of Noteholders of other
Classes or Notes.
ALLOCATIONS; PAYMENTS
On each Payment Date, the Note Trustee will apply, at the direction of the
Servicer, all amounts on deposit in the Collection Account, including net
earnings thereon (subject to the priority of withdrawals described in the
following paragraph), to pay the following amounts in the following priority:
(a) all amounts owed by the Note Issuer or the Trust to the Note
Trustee, the Delaware Trustee and the Certificate Trustee will be paid to such
persons;
(b) the Servicing Fee and all unpaid Servicing Fees from prior
Payment Dates will be paid to the Servicer;
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(c) the Quarterly Administration Fee and all unpaid Quarterly
Administration Fees from prior Payment Dates will be paid to the Administrator;
(d) so long as no Event of Default has occurred or would be caused by
such payment, all other Operating Expenses will be paid to the persons entitled
thereto;
(e) Quarterly Interest and any overdue Quarterly Interest (together
with, to the extent lawful, interest on such overdue Quarterly Interest at the
applicable Note Interest Rate) with respect to each Series of Notes will be
transferred to Certificate Trustee, as Noteholder, for distribution to the
Certificateholders;
(f) principal on the Notes payable as a result of a Note Event of
Default or on the Final Maturity Date for any Notes will be transferred to the
Certificate Trustee, as Noteholder, for distribution to the Certificateholders;
(g) funds necessary to pay Quarterly Principal for any Series of Notes
based on priorities described in each Prospectus Supplement will be transferred
to the Certificate Trustee, as Noteholder, for distribution to the applicable
Certificateholders;
(h) unpaid Operating Expenses will be paid to the persons entitled
thereto;
(i) an amount up to the sum of the Quarterly Overcollateralization
Collection and any unfunded Quarterly Overcollateralization Collections from
prior Payment Dates will be allocated to the Overcollateralization Subaccount;
(j) an amount up to the excess of the Required Capital Level with
respect to all outstanding Series of Notes over the amount in the Capital
Subaccount as of such Payment Date will be allocated to the Capital Subaccount;
(k) funds up to the net earnings on amounts in the Collection Account
for the prior quarter without cumulation will be released to the Note Issuer;
(l) if any Series of Notes has been retired as of such Payment Date,
the excess of the amount in the Overcollateralization Subaccount over the
aggregate Overcollateralization Amount with respect to all Series of Notes
remaining outstanding will be released to the Note Issuer;
(m) if any Series of Notes has been retired as of such Payment Date,
the excess of the amount in the Capital Subaccount over the aggregate Required
Capital Level with respect to all Series of Notes remaining outstanding will be
released to the Note Issuer;
(n) the balance, if any, will be allocated to the Reserve Subaccount
for distribution on subsequent Payment Dates; and
(o) following the repayment of all outstanding Series of Notes, the
balance, if any, will be released to the Note Issuer.
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If on any Payment Date funds on deposit in the General Subaccount are
insufficient to make the transfers contemplated by clauses (a) through (g)
above, the Note Trustee will (x) first, draw from amounts on deposit in the
Reserve Subaccount, (y) second, draw from amounts on deposit in the
Overcollateralization Subaccount, and (z) third, draw from amounts on deposit in
the Capital Subaccount, up to the amount of such shortfall, in order to make the
transfers described above. If on any Payment Date when there is more than one
Series of Notes outstanding, funds on deposit in the Collection Account are
insufficient to make the transfers contemplated by clauses (e) and (f) above,
such funds will be allocated among the various Series, pro rata as specified in
the related Prospectus Supplement.
For purposes of the foregoing allocations:
"QUARTERLY ADMINISTRATION FEE" means the quarterly fee payable to PG&E
as the Administrator under the Administrative Services Agreement between
PG&E and the Note Issuer, which will be specified in each Prospectus
Supplement.
"QUARTERLY INTEREST" means, with respect to any Payment Date and any
Series of Notes, the quarterly interest for such date and Series as
specified in the related Prospectus Supplement.
"QUARTERLY PRINCIPAL" means, with respect to any Payment Date and any
Series of Notes, the excess, if any, of the then-outstanding principal
balance of such Series of Notes over the outstanding principal balance
specified for such Payment Date on the applicable Expected Amortization
Schedule.
Payments to the Noteholders of a Series will be made to such holders as
specified in the related Prospectus Supplement.
ACTIONS BY NOTEHOLDERS
The Certificate Trustee, on behalf of the Trust as sole initial holder of
the Notes, has the right to vote and give consents and waivers in respect of
modifications to any Class or Series of Notes thereunder and to the provisions
of certain Basic Documents under the Note Indenture. Subject to certain
exceptions, the holders of a majority of the aggregate outstanding amount of the
Certificates of all Series (or, if less than all Series or Classes are affected,
the affected Series or Class or Classes) shall have the right to direct the
time, method and place of conducting any proceeding for any remedy available to
the Certificate Trustee, or exercising any trust or power conferred on the
Certificate Trustee under the Trust Agreement, including any right of the
Certificate Trustee as holder of the Notes of the corresponding Series or Class
or Classes, in each case unless a different percentage is specified in the Trust
Agreement; provided that: (1) such direction shall not be in conflict with any
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rule of law or with the Trust Agreement and would not involve the Certificate
Trustee in personal liability or expense; (2) the Certificate Trustee shall not
have determined that the action so directed would be unjustly prejudicial to the
holders of Certificates of such Series or Class or Classes not taking part in
such direction; (3) the Certificate Trustee may take any other action deemed
proper by the Certificate Trustee which is not inconsistent with such direction;
and (4) if a Note Event of Default with respect to such Series or Class or Notes
shall have occurred and be continuing, such direction shall not obligate the
Certificate Trustee to vote more than a corresponding majority of the related
Notes held by the Trust in favor of declaring the unpaid principal amount of the
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Notes of all Series and accrued interest thereon to be due and payable or
directing any action by the Note Trustee with respect to such Note Event of
Default. In circumstances under which the Certificate Trustee is required to
seek instructions from the holders of the Certificates of any Class with respect
to any such action or vote, the Certificate Trustee will take such action or
vote for or against any proposal in proportion to the principal amount of the
corresponding Class, as applicable, of Certificates taking the corresponding
position. See "Description of the Certificates--Voting of Notes" herein.
NOTE EVENTS OF DEFAULT; RIGHTS UPON NOTE EVENT OF DEFAULT
An "EVENT OF DEFAULT" with respect to any Series of Notes (a "NOTE EVENT OF
DEFAULT") is defined in the Note Indenture as being: (a) a default for five
days or more in the payment of any interest on any Note; (b) a default in the
payment of the then unpaid principal of any Note of any Series on the Final
Maturity Date for such Series; (c) a default in the payment of the redemption
price for any Note on the redemption date therefor; (d) a default in the
observance or performance of any covenant or agreement of the Note Issuer made
in the Note Indenture and the continuation of any such default for a period of
30 days after notice thereof is given to the Note Issuer by the Note Trustee or
to the Note Issuer and the Note Trustee by the holders of at least 25 percent in
principal amount of the Notes of such Series then outstanding; (e) any
representation or warranty made by the Note Issuer in the Note Indenture or in
any certificate delivered pursuant thereto or in connection therewith having
been incorrect in a material respect as of the time made, and such breach not
having been cured within 30 days after notice thereof is given to the Note
Issuer by the Note Trustee or to the Note Issuer and the Note Trustee by the
holders of at least 25 percent in principal amount of the Note Indenture of such
Series then outstanding; or (f) certain events of bankruptcy, insolvency,
receivership or liquidation of the Note Issuer.
If a Note Event of Default should occur and be continuing with respect to
any Series of Notes, the Note Trustee or holders of not less than a majority in
principal amount of the Notes of all Series then outstanding may declare the
principal of the Notes of all Series to be immediately due and payable. Such
declaration may, under certain circumstances set forth in the Note Indenture, be
rescinded by the holders of a majority in principal amount of the Notes of all
Series then outstanding.
If the Notes of all Series have been declared to be due and payable
following a Note Event of Default, the Note Trustee may, in its discretion,
either sell the Transition Property or elect to have the Note Issuer maintain
possession of the Transition Property and continue to apply FTA Collections as
if there had been no declaration of acceleration. There is likely to be a
limited market, if any, for the Transition Property following a foreclosure
thereon, in light of the preceding default, the unique nature of the Transition
Property as an asset and other factors discussed herein. In addition, the Note
Trustee is prohibited from selling the Transition Property following a Note
Event of Default with respect to any Series, other than a default in the payment
of any principal or redemption price or a default for five days or more in the
payment of any interest on any Note of any Series unless (a) the holders of all
the outstanding Notes of all Series consent to such sale, (b) the proceeds of
such sale are sufficient to pay in full the principal of and the accrued
interest on the outstanding Notes of all Series or (c) the Note Trustee
determines that the proceeds of the Transition Property would not be sufficient
on an ongoing basis to make all payments on the Notes of all Series as such
payments would have become due if the Notes had not been declared due and
payable, and the Note Trustee obtains the consent of the holders of 66-2/3
percent of the aggregate outstanding amount of the Notes of all Series.
Subject to the provisions of the Note Indenture relating to the duties of
the Note Trustee, in case a Note Event of Default will occur and be continuing,
the Note Trustee will be under no obligation to exercise any of the rights or
powers under the Notes at the request or direction of any of the holders of
Notes of any Series if the Note Trustee reasonably believes it will not be
adequately
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indemnified against the costs, expenses and liabilities which might be incurred
by it in complying with such request. Subject to such provisions for
indemnification and certain limitations contained in the Note Indenture, the
holders of a majority in principal amount of the outstanding Notes of all Series
(or, if less than all Classes are affected, the affected Class or Classes) will
have the right to direct the time, method and place of conducting any proceeding
or any remedy available to the Note Trustee and the holders of a majority in
principal amount of the Notes of all Series then outstanding may, in certain
cases, waive any default with respect thereto, except a default in the payment
of principal or interest or a default in respect of a covenant or provision of
the Note Indenture that cannot be modified without the waiver or consent of all
of the holders of the outstanding Notes of all Classes affected thereby.
With respect to the Notes, no holder of any Note of any Series will have
the right to institute any proceeding with respect to the Notes, unless (a) such
holder previously has given to the Note Trustee written notice of a continuing
Event of Default with respect to such Series, (b) the holders of not less than
25 percent in principal amount of the outstanding Notes of all Series have made
written request of the Note Trustee to institute such proceeding in its own name
as Note Trustee, (c) such holder or holders have offered the Note Trustee
reasonable indemnity, (d) the Note Trustee has for 60 days failed to institute
such proceeding and (e) no direction inconsistent with such written request has
been given to the Note Trustee during such 60-day period by the holders of a
majority in principal amount of the outstanding Notes of all Series.
In addition, the Servicer, the Note Trustee, each Noteholder, the
Certificate Trustee and the Certificateholders will covenant that they will not
at any time institute against the Note Issuer or the Trust any bankruptcy,
reorganization or other proceeding under any Federal or state bankruptcy or
similar law.
Neither the Certificate Trustee nor the Note Trustee in its individual
capacity, nor any holder of any ownership interest in the Note Issuer, nor any
of their respective owners, beneficiaries, agents, officers, directors,
employees, successors or assigns will, in the absence of an express agreement to
the contrary, be personally liable for the payment of the principal of or
interest on the Notes of any Series or for the agreements of the Note Issuer
contained in the Note Indenture.
CERTAIN COVENANTS OF THE NOTE ISSUER
The Note Issuer may not consolidate with or merge into any other entity,
unless (a) the entity formed by or surviving such consolidation or merger is
organized under the laws of the United States, any state thereof or the District
of Columbia, (b) such entity expressly assumes by an indenture supplemental to
the Note Indenture the Note Issuer's obligation to make due and punctual
payments upon the Notes and the performance or observance of every agreement and
covenant of the Note Issuer under the Note Indenture, (c) no Event of Default
will have occurred and be continuing immediately after such merger or
consolidation, (d) the Rating Agency Condition will have been satisfied with
respect to such transaction, (e) the Note Issuer has received an opinion of
counsel to the effect that such consolidation or merger would have no material
adverse tax consequence to the Note Issuer, the Trust, any Noteholder or any
Certificateholder and such consolidation or merger complies with the Notes and
all conditions precedent therein provided for relating to such transaction have
been complied with and (f) any action as is necessary to maintain the lien and
security interest created by the Note Indenture will have been taken.
The Note Issuer may not convey or transfer substantially all of its
properties or assets to any person or entity, unless (a) the person or entity
acquiring the properties and assets (i) is a United States citizen or an entity
organized under the laws of the United States, any state thereof or the District
of Columbia, (ii) expressly assumes by an indenture supplemental to the Note
Indenture the Note Issuer's obligation to make due and punctual payments upon
the Notes and the performance or observance of every agreement and covenant of
the
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Note Issuer under the Notes, (iii) expressly agrees by such supplemental
indenture that all right, title and interest so conveyed or transferred will be
subject and subordinate to the rights of Noteholders, (iv) unless otherwise
specified in the supplemental indenture referred to in clause (ii) above,
expressly agrees to indemnify, defend and hold harmless the Note Issuer against
and from any loss, liability or expense arising under or related to the Note
Indenture and the Notes, and (v) expressly agrees by means of such supplemental
indenture that such person (or if a group of persons, then one specified person)
shall make all filings with the Commission (and any other appropriate person)
required by the Exchange Act in connection with the Notes, (b) no Event of
Default will have occurred and be continuing immediately after such transaction,
(c) the Rating Agency Condition will have been satisfied with respect to such
transaction, (d) the Note Issuer has received an opinion of counsel to the
effect that such transaction will not have any material adverse tax consequence
to the Note Issuer, the Trust, any Noteholder or any Certificateholder and such
conveyance or transfer complies with the Note Indenture and all conditions
precedent therein provided for relating to such transaction have been complied
with and (e) any action as is necessary to maintain the lien and security
interest created by the Note Indenture shall have been taken.
The Note Issuer will not, among other things, (a) except as expressly
permitted by the Note Indenture, sell, transfer, exchange or otherwise dispose
of any of the assets of the Note Issuer, unless directed to do so by the Note
Trustee, (b) claim any credit on, or make any deduction from the principal or
interest payable in respect of, the Notes (other than amounts properly withheld
under the Code) or assert any claim against any present or former Noteholder
because of the payment of taxes levied or assessed upon any part of the
Transition Property and the other Note Collateral, (c) terminate its existence,
dissolve or liquidate in whole or in part; (d) permit the validity or
effectiveness of the Notes to be impaired, (e) permit the lien of the Note
Indenture to be amended, hypothecated, subordinated, terminated or discharged or
permit any person to be released from any covenants or obligations with respect
to the Notes except as may be expressly permitted by the Indenture, (f) permit
any lien, charge, excise, claim, security interest, mortgage or other
encumbrance, other than the lien and security interest created by the Indenture,
to be created on or extend to or otherwise arise upon or burden the Collateral
or any part thereof or any interest therein or the proceeds thereof or (g)
permit the lien of the Note Indenture not to constitute a valid first priority
security interest in the Collateral.
The Note Issuer may not engage in any business other than financing,
purchasing, owning and managing the Transition Property in the manner
contemplated by the Notes, the Sale Agreement, the Servicing Agreement, the
Trust Agreement, the Note Purchase Agreement between the Note Issuer and the
Trust, or certain related documents (collectively, the "BASIC DOCUMENTS") and
activities incidental thereto.
The Note Issuer will not issue, incur, assume, guarantee or otherwise
become liable for any indebtedness except for the Notes.
The Note Issuer will not, except for any Eligible Investments as
contemplated by the Basic Documents, make any loan or advance or credit to, or
guarantee, endorse or otherwise become contingently liable in connection with
the obligations, stocks or dividends of, or own, purchase, repurchase or acquire
(or agree contingently to do so) any stock, obligations, assets or securities
of, or any other interest in, or make any capital contribution to, any other
person. The Note Issuer will not, except as contemplated by the Basic
Documents, make any expenditure (by long-term or operating lease or otherwise)
for capital assets (either realty or personalty). The Note Issuer will not,
directly or indirectly, make payments to or distributions from the Collection
Account except in accordance with the Basic Documents.
The Note Issuer will not make any payments, distributions or dividends to
any holder of beneficial interests in the Note Issuer in respect of such
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beneficial interest for any Billing Period unless no Note Event of Default shall
have occurred and be continuing and any such distributions do not cause the book
value of the remaining equity in the Note Issuer to decline below 0.50% of the
initial principal amount of all Notes issued and outstanding pursuant to the
Indenture.
The Note Issuer will cause the Servicer to deliver to the Note Trustee and
the Certificate Trustee the annual accountant's certificates, compliance
certificates, reports regarding distributions and statements to Noteholders and
the Certificateholders required by the Servicing Agreement.
REPORTS TO NOTEHOLDERS
With respect to each Series of Notes, on or prior to each Payment Date, the
Servicer will prepare and provide to the Note Issuer, the Infrastructure Bank,
the Note Trustee and the Certificate Trustee a statement (the "QUARTERLY
SERVICER'S CERTIFICATE") to be delivered to the Noteholders on such Payment
Date. With respect to each Series of Notes, each such statement to be delivered
to Noteholders will include (to the extent applicable) the following information
(and any other information so specified in the related Prospectus Supplement) as
to the Notes of such Series with respect to such Payment Date or the period
since the previous Payment Date, as applicable:
(a) the amount of the distribution to Noteholders allocable to
principal;
(b) the amount of the distribution to Noteholders allocable to
interest;
(c) the aggregate outstanding principal balance of the Notes, after
giving effect to payments allocated to principal reported under (a) above; and
(d) the difference, if any, between the amount specified in (c) above
and the principal amount scheduled to be outstanding on such date according to
the Expected Amortization Schedule.
Within the prescribed period of time for tax reporting purposes after the
end of each calendar year during the term of the Notes, the Note Trustee will
mail to each person who at any time during such calendar year has been a
Noteholder and received any payment thereon, a statement containing certain
information for the purposes of such Noteholder's preparation of Federal and
state income tax returns. See "Certain Federal Income Tax Consequences" and
"State Taxation" herein.
ANNUAL COMPLIANCE STATEMENT
The Note Issuer will be required to file annually with the Note Trustee,
the Certificate Trustee and the Rating Agencies a written statement as to the
fulfillment of its obligations under the Notes.
DESCRIPTION OF THE CERTIFICATES
GENERAL
The Trust will issue the Certificates pursuant to the Trust Agreement, the
form of which is filed as an exhibit to the Registration Statement of which this
Prospectus is a part. The following summary describes the material terms and
provisions of the Trust Agreement. The particular terms of the Certificates of
any Class will be established in a supplement to the Trust Agreement, and the
material terms thereof will be described in the related Prospectus Supplement.
The following summary description of the Certificates is subject to, and is
qualified in its entirety by reference to, all the provisions of the Trust
Agreement and the
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Certificates, a form of which is also filed as an exhibit to the Registration
Statement.
The Certificates will be issued in fully registered form only. Each Class
of Certificates offered hereby will represent a fractional undivided interest in
the corresponding Class of Notes, all monies due and to become due under such
corresponding Class of Notes, payments pursuant to any related Swap Agreement
and funds from time to time deposited with the Trustee in certain accounts
relating to the Trust. Each Certificate of each Class will correspond to a pro
rata share of the outstanding principal amount of the corresponding Class of the
Notes held in the Trust and will be issued in minimum denominations specified in
the applicable Prospectus Supplement.
Each Class of Certificates will bear interest at the rate per annum borne
by the corresponding Class of the Notes, unless a Swap Agreement is entered into
in connection with the issuance of any Class of Certificates, as described in
the related Prospectus Supplement, in which case a Series or Class of
Certificates may bear interest at a variable rate. See "Description of the
Notes--Interest and Principal" herein. Payments of interest and principal made
in respect of any Class of Notes are required to be passed through to holders of
the corresponding Class of Certificates at the times and in the manner described
herein. See "--Payments and Distributions" below and "Description of the Notes-
- -Interest and Principal" herein.
The Certificates do not represent an interest in or obligation of the State
of California, the Infrastructure Bank, any other governmental agency or
instrumentality or the Seller or any of its affiliates, other than the Note
Issuer. The Certificates will not be guaranteed or insured by the State of
California, the Infrastructure Bank, the Trust or any other governmental agency
or instrumentality or by the Seller or any of its affiliates. Neither the full
faith and credit nor the taxing power of the State of California or any agency
or instrumentality thereof is pledged to the distributions of principal of, or
interest on, the Certificates. The Certificates represent beneficial interests
in the Trust only.
STATE PLEDGE
Pursuant to Section 841(c) of the PU Code, the Infrastructure Bank, on
behalf of the State of California, pledges and agrees with the Trust and the
Holders of the Certificates that the State of California shall neither limit nor
alter the FTA Charges, the Transition Property, or the Financing Order or Advice
Letters relating thereto, or any rights thereunder, until the Certificates,
together with interest thereon, are fully paid and discharged, provided nothing
contained in this pledge and agreement shall preclude such limitation or
alteration if and when adequate provision shall be made by law for the
protection of the Holders (the "STATE PLEDGE").
PAYMENTS AND DISTRIBUTIONS
The Certificate Trustee is scheduled to receive payments of interest on and
principal of the Notes (in each case, the amounts paid to any Series or Class of
the Notes will be determined from time to time in accordance with the provisions
described under "Description of the Notes--Allocations; Payments" herein) on
each Payment Date.
The Certificate Trustee will distribute on each Distribution Date to the
holders of each Class of Certificates all payments of principal and interest
with respect to the corresponding Class of Notes (other than payments received
following a payment default in respect of such Class of Notes), or, in lieu of
such interest, payments under the related Swap Agreement with respect to
interest, the receipt of which is confirmed by the Certificate Trustee by 1:00
p.m. (New York City time) on such Distribution Date or, if such receipt is
confirmed after 1:00 p.m. (New York City time) on such Distribution Date, then
on the following business day. Each such distribution other than the final
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distribution with respect to any Certificate will be made by the Certificate
Trustee to the holders of record of the Certificates of the applicable Class on
the Record Date in respect of such Distribution Date. If a payment of principal
or interest on any Class of the Notes (other than a payment received following a
payment default in respect of such Class of Notes) is not received by the
Certificate Trustee on a Distribution Date but is received within five days
thereafter, it will be distributed to such holders of record on the date receipt
thereof is confirmed by the Certificate Trustee, if such receipt is confirmed by
the Certificate Trustee by 1:00 p.m. (New York City time) or, if such receipt is
confirmed after 1:00 p.m. (New York City time), then on the following business
day. If such payment is received by the Certificate Trustee after such five-day
period, it will be treated as a payment received following a payment default in
respect of such Class of Notes and distributed as described below. The final
distribution with respect to any Certificate, however, will be made only upon
presentation and surrender of such Certificate at the office or agency of the
Certificate Trustee specified in the notice given by the Certificate Trustee
with respect to such final distribution.
Any payment received by the Certificate Trustee following a payment default
in respect of any Class of the Notes ("SPECIAL PAYMENTS") will be distributed on
the later of (i) the date such receipt is confirmed by the Certificate Trustee
and (ii) the date on which any Special Payment is scheduled to be distributed by
the Certificate Trustee (a "SPECIAL DISTRIBUTION DATE"). However, in the case
of any such Special Payment receipt of which is confirmed after 1:00 p.m. (New
York City time), such Special Payment will be distributed on the following day.
The Certificate Trustee will mail notice to the holders of record of
Certificates of the applicable Class as of the most recent Record Date not less
than 20 days prior to the Special Distribution Date on which any Special Payment
is scheduled to be distributed in respect of Certificates of such Class stating
such anticipated Special Distribution Date. Each distribution of any such
Special Payment will be made by the Certificate Trustee on the Special
Distribution Date to the holders of record of the Certificates of such Class as
of the most recent Record Date. See "--Events of Default" below.
The Trust Agreement requires that the Certificate Trustee establish and
maintain, for the Trust and for the benefit of the holders of each Class of
Certificates, one or more non-interest bearing accounts (a "CERTIFICATE
ACCOUNT") for the deposit of payments on the Notes corresponding to such Class.
Pursuant to the terms of the Trust Agreement, the Certificate Trustee is
required to deposit any payments received by it with respect to any Class of
Notes in the corresponding Certificate Account. All amounts so deposited will
be distributed by the Certificate Trustee to holders of the applicable Class of
Certificates on a Distribution Date or a Special Distribution Date, as
appropriate, unless a different date for distribution of such amount is
specified herein.
At such time, if any, as the Certificates of any Class are issued in the
form of Definitive Certificates and not to DTC or its nominee, distributions by
the Certificate Trustee from the Certificate Account with respect to such Class
on a Distribution Date or a Special Distribution Date will be made by check
mailed to each holder of a Definitive Certificate of such Class of record on the
applicable Record Date at its address appearing on the register maintained with
respect to the Certificates of such Series, or, upon application by a holder of
any Class of Certificates in the principal amount of $1,000,000 or more to the
Certificate Trustee not later than the applicable Record Date, by wire transfer
to an account maintained by the payee in New York, New York. The final
distribution for each Class of Certificates, however, will be made only upon
presentation and surrender of the Certificates of such Class at the office or
agency of the Certificate Trustee specified in the notice or agency given by the
Certificate Trustee of such final distribution. The Certificate Trustee will
mail such notice of the final distribution to the Certificateholders of such
Class, specifying the date set for such final distribution and the amount of
such distribution.
If any Special Distribution Date or other date specified herein for
distribution of any distributions to Certificateholders is not a Certificate
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Business Day, distributions scheduled to be made on such Special Distribution
Date or other date may be made on the next succeeding Certificate Business Day
and no interest shall accrue upon such distribution during the intervening
period. "CERTIFICATE BUSINESS DAY" means any day other than a Saturday, a
Sunday or a day on which banking institutions or trust companies in New York,
New York or San Francisco, California are authorized or obligated by law,
regulation or executive order to remain closed.
VOTING OF THE NOTES
The Certificate Trustee, as sole initial holder of the Notes, has the right
to vote and give consents and waivers in respect of modifications to any Class
of Notes. Subject to certain exceptions, the holders of a majority of the
aggregate outstanding amount of the Certificates of all Series (or, if less than
all Series or Classes are affected, the affected Series or Class or Classes)
shall have the right to direct the time, method and place of conducting any
proceeding for any remedy available to the Certificate Trustee, or exercising
any trust or power conferred on the Certificate Trustee under the Trust
Agreement, including any right of the Certificate Trustee as holder of the Notes
of the corresponding Series or Class or Classes, in each case unless a different
percentage is specified in the Trust Agreement; provided that: (1) such
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direction shall not be in conflict with any rule of law or with the Trust
Agreement and would not involve the Certificate Trustee in personal liability or
expense; (2) the Certificate Trustee shall not have determined that the action
so directed would be unjustly prejudicial to the holders of Certificates of such
Series or Class or Classes not taking part in such direction; and (3) the
Certificate Trustee may take any other action deemed proper by the Certificate
Trustee which is not inconsistent with such direction. If the Certificate
Trustee is required to seek instructions from the holders of the Certificates of
any Class with respect to any such action or vote, the Certificate Trustee will
take such action or vote for or against any proposal in proportion to the
principal amount of the corresponding Class, as applicable, or Certificates
taking the corresponding position.
EVENTS OF DEFAULT
An event of default with respect to any Class of Certificates under the
Trust Agreement (a "CERTIFICATE EVENT OF DEFAULT") is defined as the occurrence
and continuance of a Note Event of Default or a breach by the State of
California of the State Pledge. For a description of the Note Events of
Default, see "Description of the Notes -- Note Events of Default; Rights Upon
Note Event of Default" herein.
The Trust Agreement provides that, if a Note Event of Default shall have
occurred and be continuing with respect to any Class of Certificates, the
Certificate Trustee may and, upon the written direction of holders representing
not less than a majority of the aggregate outstanding principal amount of the
Certificates of all Series, shall vote all the Notes of all Series in favor of
declaring the unpaid principal amount of all Series of Notes and accrued
interest thereon to be due and payable. In addition, the Trust Agreement
provides that, if a Note Event of Default with respect to any Class of
Certificates shall have occurred and be continuing, the Certificate Trustee may
and, upon the written direction of holders representing not less than a majority
of the aggregate outstanding principal amount of the Certificates of all Series,
shall vote all the Notes of all Series in favor of directing the Note Trustee as
to the time, method and place of conducting any proceeding for any remedy
available to the
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Note Trustee or of exercising any trust or power conferred on the Note Trustee
under the Note Indenture.
As an additional remedy, if a Note Event of Default shall have occurred and
be continuing with respect to a particular Series or Class of Certificates, the
Trust Agreement provides that the Certificate Trustee may and, upon the written
direction of the holders of Certificates representing not less than a majority
of the aggregate outstanding principal amount of the Certificates of such Series
or Class, will sell any Note or Notes, without recourse to or warranty by the
Certificate Trustee or any Certificateholder, to any person, for cash. The
Certificate Trustee may, but shall not be obligated to refrain, in its sole
discretion, from liquidating any Notes if (i) the Certificate Trustee determines
that amounts receivable from the Note Collateral with respect to the applicable
Class of Notes will be sufficient to pay (a) all principal of and interest on
that Class of Notes in accordance with its terms without regard to any
declaration of acceleration thereof and (b) all sums due to the Certificate
Trustee and any other administrative expenses specified in the Trust Agreement,
and (ii) holders of Certificates representing not less than a majority of the
aggregate outstanding principal amount of the Certificates of all Series have
not directed the Certificate Trustee to sell any Note or Notes. In addition,
the Certificate Trustee is prohibited from selling any Notes following certain
nonpayment Note Events of Default unless (x) the Certificate Trustee determines
that the amounts receivable from the Note Collateral with respect to each Class
of Notes are not sufficient to pay in full the principal of and accrued interest
on the Notes of each such Class and to pay all sums due to the Certificate
Trustee and other administrative expenses specified in the Trust Agreement and
the Certificate Trustee obtains the written consent of holders of Certificates
of each such Class representing 66 2/3% of the aggregate outstanding principal
amount of each such Class of Certificates or (y) the Certificate Trustee obtains
the consent of 100% of the aggregate outstanding principal amount of each such
Class of Certificates. Any proceeds received by the Certificate Trustee upon
any such sale will be deposited in the Certificate Account for such Class and
will be distributed to the holders of Certificates of such Class on a Special
Distribution Date.
If a Certificate Event of Default in the form of a breach by the State of
California of the State Pledge has occurred, then, as the sole and exclusive
remedy for such breach, the Certificate Trustee, in its own name and as trustee
of an express trust, as holder of the Notes, shall be, to the extent permitted
by State and Federal law, entitled and empowered to institute any suits, actions
or proceedings at law, in equity or otherwise, to enforce the State Pledge and
to collect any monetary damages as a result of a breach thereof, and may
prosecute any such suit, action or proceeding to judgment or final decree.
Any funds (a) representing payments received with respect to any Series or
Class of Notes in default, (b) representing the proceeds from the sale by the
Certificate Trustee of any Class of Notes or (c) otherwise arising from a
Certificate Event of Default, held by the Certificate Trustee in a Certificate
Account shall, to the extent practicable, be invested and reinvested by the
Certificate Trustee in Eligible Investments permitted under the Trust Agreement
maturing in not more than 60 days or such lesser time as is required for the
distribution of any such funds on a Special Distribution Date, pending the
distribution of such funds to Certificateholders as described herein.
The Trust Agreement provides that, with respect to the Certificates of any
Class, within 30 days after the occurrence of any event that is, or after notice
or lapse of time or both would become, a Certificate Event of Default with
respect to such Class of Certificates (a "DEFAULT"), the Certificate Trustee
will give to the Infrastructure Bank, the Note Trustee and the holders of such
Certificates notice, transmitted by mail, of all such uncured or unwaived
Defaults known to it. However, except in the case of a Default relating to the
payment of principal of or interest on any of the Notes, the Certificate Trustee
will be protected in withholding such notice if in good faith it determines that
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the withholding of such notice is in the interests of the holders of the
Certificates of such Class.
The Trust Agreement contains a provision entitling the Certificate Trustee
to be indemnified by the holders of the Certificates before proceeding to
exercise any right or power under the Trust Agreement at the request or
direction of Certificateholders.
In certain cases, the holders of Certificates representing not less than a
majority of the outstanding aggregate principal amount of the Certificates of
all Series may waive any past Default or Certificate Event of Default under the
Trust Agreement and thereby annul any previous direction given by the
Certificate Trustee with respect thereto, except a Default (i) in the deposit or
distribution of any payment on the Notes or Special Payment required to be made
with respect to any Class of Certificates, (ii) in the payment of principal of
or interest on any of the Notes, and (iii) in respect of any covenant or
provision of the Trust Agreement that cannot be modified or amended without the
consent of the holder of each Certificate of all Classes affected hereby. Upon
any such direction, the Certificate Trustee shall vote a corresponding
percentage of the corresponding Class of Notes in favor of such waiver. The
Notes provide that, with certain exceptions, the holders of not less than a
majority in aggregate unpaid principal amount of the Notes of all Series may
waive any Note Event of Default or any event that is, or after notice or passage
of time, or both, would be, a Note Event of Default.
The Trust may hold two or more Classes of Notes, each of which may have a
different interest rate and, in the case of different Classes, a different or
potentially different schedule of the repayment of principal and different
rights in the security therefor. Accordingly, the holders of Certificates of
each Class may have divergent or conflicting interests from the holders of
Certificates of other Classes.
OPTIONAL REDEMPTION
The Trust shall redeem any Series of Certificates if the related of Series
Notes is redeemed. Unless otherwise specified in the related Prospectus
Supplement, notice of such redemption will be given by the Trust to each holder
of Certificates to be redeemed by first-class mail, postage prepaid, mailed not
less than five days nor more than 25 days prior to the date of redemption.
REPORTS TO CERTIFICATEHOLDERS
On each Distribution Date, Special Distribution Date or any other date
specified in the Trust Agreement for distribution of any payments with respect
to any Class of Certificates, the Certificate Trustee will include with each
distribution to holders of Certificates of such Class a statement with respect
to such distribution to be made on such Distribution Date, Special Distribution
Date or other date, as the case may be, setting forth the following information,
in each case, to the extent received by the Certificate Trustee from the Note
Trustee, no later than two Certificate Business Days prior to such Distribution
Date, Special Distribution Date or other date specified herein for such
distribution:
(a) the amount of the distribution to Certificateholders allocable to
(i) principal and (ii) interest, in each case per $1,000 original principal
amount of each Class of Certificates;
(b) the aggregate outstanding principal balance of the Certificates,
after giving effect to distributions allocated to principal reported under (a)
above; and
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(c) the difference, if any, between the amount specified in (b) above
and the principal amount scheduled to be outstanding on such date according to
the Expected Amortization Schedule.
Within the prescribed period of time for tax reporting purposes after the
end of each calendar year during the term of the Notes, the Certificate Trustee
will mail to each person who at any time during such calendar year has been a
Certificateholder and received any distribution thereon, a statement containing
certain information for the purposes of such Certificateholder's preparation of
Federal and state income tax returns. See "Certain Federal Income Tax
Consequences" and "State Taxation" herein.
AMENDMENTS
The Infrastructure Bank (with the prior written approval of the Note
Issuer) and the Certificate Trustee may amend the Trust Agreement from time to
time, without the consent of the Certificateholders of any Series, (1) to add to
the covenants of the Infrastructure Bank for the benefit of the
Certificateholders, or to surrender any right or power conferred upon the
Infrastructure Bank; (2) to correct or supplement any provision in the Trust
Agreement or in any supplemental agreement which may be defective or
inconsistent with any other provision in the Trust Agreement or in any
supplemental agreement or to make any other provisions with respect to matters
or questions arising under the Trust Agreement; provided that any such action
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shall not adversely affect the interests of the Certificateholders; (3) to cure
any ambiguity or correct any mistake; (4) to qualify, if necessary, the Trust
Agreement (including any supplement thereto) under the Trust Indenture Act of
1939, as amended or (5) to provide for the issuance of the Certificates of any
Series or Class, or to provide for the execution and delivery of any Swap
Agreement.
In addition, the Infrastructure Bank (with the prior written approval of
the Note Issuer) and the Certificate Trustee may amend the Trust Agreement with
the consent of Certificateholders holding not less than a majority of the
aggregate outstanding principal amount of the Certificates of all affected
Classes. No amendment, however, may, without the consent of each
Certificateholder affected thereby, (a) reduce in any manner the amount of, or
delay the timing of, deposits or distributions on any Certificate, (b) permit
the disposition of any Note held by the Trust except as permitted by the Trust
Agreement, or otherwise deprive any Certificateholder of the benefit of the
ownership of the related Notes held by the Trust, (c) reduce the aforesaid
percentage of the aggregate outstanding principal amount of the Certificates the
holders of which are required to consent to any such amendment, (d) modify the
provisions in the Trust Agreement relating to amendments with the consent of
Certificateholders, except to increase the percentage vote necessary to approve
amendments or to add further provisions which cannot be modified or waived
without the consent of all Certificateholders, or (e) adversely affect the
status of the Trust as a grantor trust taxable as a corporation for federal
income tax purposes. Promptly following the execution of any amendment to the
Trust Agreement (other than an amendment described in the preceding paragraph),
the Certificate Trustee will furnish written notice of the substance of such
amendment to each Certificateholder.
Any supplement to the Trust Agreement executed in connection with the
issuance of one or more new Series of Certificates will not be considered an
amendment to the Trust Agreement.
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LIST OF CERTIFICATEHOLDERS
Upon written request of any Certificateholder or group of
Certificateholders of any Series or of all outstanding Series of record holding
Certificates evidencing not less than 10 percent of the aggregate outstanding
principal amount of the Certificates of such Series or all Series, as
applicable, the Certificate Trustee will afford such Certificateholder or
Certificateholders access during business hours to the current list of
Certificateholders of such Series or of all outstanding Series, as the case may
be, for purposes of communicating with other Certificateholders with respect to
their rights under the Trust Agreement.
The Trust Agreement does not provide for any annual or other meetings of
Certificateholders.
REGISTRATION AND TRANSFER OF THE CERTIFICATES
If so specified in the related Prospectus Supplement, one or more Classes
of Certificates will be issued in definitive form and will be transferable and
exchangeable at the office of the registrar identified in the related Prospectus
Supplement. Unless otherwise specified in the related Prospectus Supplement, no
service charge will be made for any such registration or transfer of such
Certificates, but the owner may be required to pay a sum sufficient to cover any
tax or other governmental charge.
Each Class of Certificates will be issued in the minimum initial
denominations set forth in the related Prospectus Supplement and, except as
otherwise provided in the related Prospectus Supplement, in integral multiples
thereof.
Distributions of interest and principal will be made on each Distribution
Date to the Certificateholders in whose names the Certificates were registered
on the related Record Date.
BOOK-ENTRY REGISTRATION
If so specified in the related Prospectus Supplement, one or more Classes
of Certificates initially may be Book-Entry Certificates, which are initially
represented by one or more certificates registered in the name of Cede, as
nominee of DTC, or another securities depository, and are available only in the
form of book-entries. Any Book-Entry Certificates will initially be registered
in the name of Cede, the nominee of DTC. Holders may also hold Certificates of
a Class through Centrale de Livraison de Valeurs Mobilieres S.A. ("CEDEL") or
the Euroclear System ("EUROCLEAR") (in Europe), if they are participants in such
systems or indirectly through organizations that are participants in such
systems.
Cede, as nominee for DTC, will hold the global Certificate or Certificates.
CEDEL and Euroclear will hold omnibus positions on behalf of their participants
through customers' securities accounts in CEDEL's and Euroclear's names on the
books of their respective Depositaries (as defined herein) which in turn will
hold such positions in customers' securities accounts in the Depositaries' names
on the books of DTC. Citibank, N.A. will act as depositary for CEDEL and Morgan
Guaranty Trust Company of New York will act as depositary for Euroclear (in such
capacities, the "DEPOSITARIES").
DTC is a limited-purpose trust company organized under the laws of the
State of New York, a member of the Federal Reserve System, a "clearing
corporation" within the meaning of the New York Uniform Commercial Code, and a
"clearing agency" registered pursuant to the provisions of Section 17A of the
Securities Exchange Act of 1934, as amended. DTC was created to hold securities
for its participating organizations, which are the Participants, and facilitate
the settlement of securities transactions between Participants through
electronic book-entry changes in accounts of its Participants, thereby
eliminating the need for physical movement of securities. Participants include
underwriters,
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securities brokers and dealers, banks, trust companies and clearing corporations
and may include certain other organizations. Indirect access to the DTC system
also is available to Indirect Participants, which are others such as banks,
brokers, dealers and trust companies that clear through or maintain a custodial
relationship with a Participant, either directly or indirectly.
Transfers between Participants will occur in accordance with DTC rules.
Transfers between CEDEL Participants (as defined herein) and Euroclear
Participants (as defined herein) will occur in accordance with their respective
rules and operating procedures.
Cross-market transfers between persons holding directly or indirectly
through DTC, on the one hand, and directly or indirectly through CEDEL or
Euroclear Participants, on the other, will be effected in DTC in accordance with
DTC rules on behalf of the relevant European international clearing system by
its Depositary. Cross-market transactions will require delivery of instructions
to the relevant European international clearing system by the counterparty in
such system in accordance with its rules and procedures and within its
established deadlines (European time). The relevant European international
clearing system will, if the transaction meets its settlement requirements,
deliver instructions to its Depositary to take action to effect final settlement
on its behalf by delivering or receiving bonds in DTC, and making or receiving
distributions in accordance with normal procedures for same-day funds settlement
applicable to DTC. CEDEL Participants and Euroclear Participants may not
deliver instructions directly to the Depositaries.
Because of time-zone differences, credits of securities received in CEDEL
or Euroclear as a result of a transaction with a Participant will be made during
subsequent settlement processing and dated the Certificate Business Day
following the DTC settlement date. Such credits or any transactions in such
Certificates settled during such processing will be reported to the relevant
Euroclear or CEDEL Participant on such Certificate Business Day. Cash received
in CEDEL or Euroclear as a result of sales of Certificates by or through a CEDEL
Participant or a Euroclear Participant to a DTC Participant will be received
with value on the DTC settlement date but will be available in the relevant
CEDEL or Euroclear cash account only as of the Certificate Business Day
following settlement in DTC.
Certificateholders that are not Participants or Indirect Participants but
desire to purchase, sell or otherwise transfer ownership of, or other interests
in, Certificates may do so only through Participants and Indirect Participants.
In addition, Certificateholders will receive all distributions of principal of
and interest on the Certificates from the Certificate Trustee through DTC and
its Participants. Under a book-entry format, Certificateholders will receive
distributions after the related Distribution Date, as the case may be, because,
while distributions are required to be forwarded to Cede, as nominee for DTC, on
each such date, DTC will forward such distributions to its Participants, which
thereafter will be required to forward them to Indirect Participants or holders
of beneficial interests in the Certificates. The Certificate Trustee, the
Seller, the Servicer and any paying agent, transfer agent or registrar may treat
the registered holder in whose name any Certificate is registered (expected to
be Cede) as the absolute owner thereof (whether or not such Certificate is
overdue and notwithstanding any notice of ownership or writing thereon or any
notice to the contrary) for the purpose of making distributions and for all
other purposes.
Unless and until Definitive Certificates (as defined below) are issued, it
is anticipated that the only "holder" of Book-Entry Certificates of any Series
will be Cede, as nominee of DTC. Certificateholders will only be permitted to
exercise their rights as Certificateholders indirectly through Participants and
DTC. All references herein to actions by Certificateholders thus refer to
actions taken by DTC upon instructions from its Participants, and all references
herein to distributions, notices, reports and statements to Certificateholders
refer to distributions, notices, reports and statement to Cede, as the
registered
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holder of the Certificates, for distribution to the beneficial owners of the
Certificate in accordance with DTC procedures.
While any Book-Entry Certificates of a Series are outstanding (except under
the circumstances described below), under the rules, regulations and procedures
creating and affecting DTC and its operations (the "RULES"), DTC is required to
make book-entry transfers among Participants on whose behalf it acts with
respect to the Book-Entry Certificates and is required to receive and transmit
distributions of principal of, and interest on, the Book-Entry Certificates.
Participants with whom Certificateholders have accounts with respect to Book-
Entry Certificates are similarly required to make book-entry transfers and
receive and transmit such distributions on behalf of their respective
Certificateholders. Accordingly, although Certificateholders will not possess
physical certificates, the Rules provide a mechanism by which Certificateholders
will receive distributions and will be able to transfer their interests.
Because DTC can only act on behalf of Participants, who in turn act on
behalf of Indirect Participants and certain banks, the ability of holders of
beneficial interests in the Certificates to pledge Certificates to persons or
entities that do not participate in the DTC system, or otherwise take actions in
respect of such Certificates, may be limited due to the lack of a Definitive
Certificate for such Certificates.
DTC has advised the Certificate Trustee that it will take any action
permitted to be taken by a Certificateholder under the Trust Agreement and the
related Prospectus Supplement only at the direction of one or more Participants
to whose account with DTC the Certificates are credited. Additionally, DTC has
advised the Certificate Trustee that it may take actions with respect to the
Certificateholders' Interest that might conflict with other of its actions with
respect thereto.
CEDEL is incorporated under the laws of Luxembourg as a professional
depository. CEDEL holds securities for its participating organizations ("CEDEL
PARTICIPANTS") and facilitates the clearance and settlement of securities
transactions between CEDEL Participants through electronic book-entry changes in
accounts of CEDEL Participants, thereby eliminating the need for physical
movement of securities. Transactions may be settled in CEDEL in any of 28
currencies, including United States dollars. CEDEL provides to CEDEL
Participants, among other things, services for safekeeping, administration,
clearance and settlement of internationally traded securities and securities
lending and borrowing. CEDEL interfaces with domestic markets in several
countries. As a professional depository, CEDEL is subject to regulation by the
Luxembourg Monetary Institute. CEDEL Participants are recognized financial
institutions around the world including underwriters, securities brokers and
dealers, banks, trust companies, clearing corporations and certain other
organizations and may include any underwriters, agents or dealers with respect
to a Series of Certificates offered hereby. Indirect access to CEDEL is also
available to others, such as banks, brokers, dealers and trust companies that
clear through or maintain a custodial relationship with a CEDEL Participant,
either directly or indirectly.
Euroclear was created in 1968 to hold securities for participants of the
Euroclear System ("EUROCLEAR PARTICIPANTS") and to clear and settle transactions
between Euroclear Participants through simultaneous electronic book-entry
delivery against payment, thereby eliminating the need for physical movement of
securities and any risk from lack of simultaneous transfers of securities and
cash. Transactions may now be settled in any of 29 currencies, including United
States dollars. The Euroclear System includes various other services, including
securities lending and borrowing, and interfaces with domestic markets in
several countries generally similar to the arrangements for cross-market
transfers with DTC described above. The Euroclear System is operated by Morgan
Guaranty Trust Company of New York, Brussels, Belgium office (the "EUROCLEAR
OPERATOR"), under contract with Euroclear Clearance System S.C., a Belgian
cooperative corporation (the "COOPERATIVE"). All operations are conducted by
the Euroclear Operator, and all Euroclear securities clearance accounts and
Euroclear cash accounts are
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accounts with the Euroclear Operator, not the Cooperative. The Cooperative
establishes policy for Euroclear on behalf of Euroclear Participants. Euroclear
Participants include banks (including central banks), securities brokers and
dealers and other professional financial intermediaries. Indirect access to
Euroclear is also available to other firms that clear through or maintain a
custodial relationship with a Euroclear Participant, either directly or
indirectly.
The Euroclear Operator is the Belgian branch of a New York banking
corporation that is a member bank of the Federal Reserve System. As such, it is
regulated and examined by the Board of Governors of the Federal Reserve System
and the New York State Banking Department, as well as the Belgian Banking
Commission.
Securities clearance accounts and cash accounts with the Euroclear Operator
are governed by the Terms and Conditions Governing Use of Euroclear and the
related Operating Procedures of Euroclear and applicable Belgian law
(collectively, the "TERMS AND CONDITIONS"). The Terms and Conditions govern
transfers of securities and cash within Euroclear, withdrawals of securities and
cash from Euroclear and receipts of payments with respect to securities in
Euroclear. All securities in Euroclear are held on a fungible basis without
attribution of specific securities to specific securities clearance accounts.
The Euroclear Operator acts under the Terms and Conditions only on behalf of
Euroclear Participants, and has no record of or relationship with persons
holding through Euroclear Participants.
Distributions with respect to Certificates held through CEDEL or Euroclear
will be credited to the cash accounts of CEDEL Participants or Euroclear
Participants in accordance with the relevant systems' rules and procedures, to
the extent received by its Depositary. Such distributions will be subject to
tax reporting in accordance with relevant United States tax laws and
regulations. See "Certain Federal Income Tax Consequences" herein. CEDEL or
the Euroclear Operator, as the case may be, will take any other action permitted
to be taken by a Certificateholder under the Trust Agreement or the relevant
Prospectus Supplement on behalf of a CEDEL Participant or Euroclear Participant
only in accordance with its relevant rules and procedures and subject to its
Depositary's ability to effect such actions on its behalf through DTC.
Although DTC, CEDEL and Euroclear have agreed to the foregoing procedures
in order to facilitate transfers of Certificates among participants of DTC,
CEDEL and Euroclear, they are under no obligation to perform or continue to
perform such procedures and such procedures may be discontinued at any time.
DEFINITIVE CERTIFICATES
Certificates of a Class will be issued in registered form to
Certificateholders, or their nominees, rather than to DTC (such Certificates
being referred to herein as "DEFINITIVE CERTIFICATES") only under the
circumstances provided in the Trust Agreement, which will include if (a) DTC
advises the Certificate Trustee in writing that DTC is no longer willing or able
to discharge properly its responsibilities as nominee and depository with
respect to the Book-Entry Certificates of such Class and the Certificate Trustee
or the Infrastructure Bank is unable to locate a qualified successor, (b) the
Infrastructure Bank (with the prior written approval of the Note Issuer) elects
to terminate the book-entry system through DTC or (c) after the occurrence of an
Event of Default under the terms of the Trust Agreement, holders of Certificates
representing not less than 50 percent of the aggregate outstanding principal
amount of the Certificates of all Series advise DTC in writing that the
continuation of a book-entry system through DTC (or a successor thereto) to the
exclusion of any physical certificates being issued to Certificateholders is no
longer in the best interests of Certificateholders. Upon issuance of Definitive
Certificates of a Class, such Certificates will be transferable directly (and
not exclusively on a book-entry basis) and registered
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holders will deal directly with the Certificate Trustee with respect to
transfers, notices and distributions.
Upon the occurrence of any of the events described in the immediately
preceding paragraph, DTC is required to notify all Participants of the
availability through DTC of Definitive Certificates. Upon surrender by DTC of
the definitive securities representing the Certificates and instructions for
registration, the Certificate Trustee will issue the Certificates in the form of
Definitive Certificates, and thereafter the Certificate Trustee will recognize
the holders of such Definitive Certificates as Certificateholders under the
Trust Agreement and the related Prospectus Supplement.
Distribution of principal of and interest on the Certificates will be made
by the Certificate Trustee directly to Certificateholders in accordance with the
procedures set forth herein and in the Trust Agreement and the related
Prospectus Supplement. Interest distributions and principal distributions will
be made to Certificateholders in whose names the Definitive Certificates were
registered at the close of business on the related Record Date. Distributions
will be made by check mailed to the address of such Certificateholder as it
appears on the register maintained by the Certificate Trustee. The final
distribution on any Certificate (whether Definitive Certificates or Certificates
registered in the name of Cede), however, will be made only upon presentation
and surrender of such Certificate on the final distribution date at such office
or agency as is specified in the notice of final distribution to
Certificateholders. The Certificate Trustee will provide such notice to
registered Certificateholders not later than the fifth day of the month of the
final distribution.
Definitive Certificates will be transferable and exchangeable at the
offices of the transfer agent and registrar, which initially will be the
Certificate Trustee. No service charge will be imposed for any registration of
transfer or exchange, but the transfer agent and registrar may require payment
of a sum sufficient to cover any tax or other governmental charge imposed in
connection therewith.
CONDITIONS OF ISSUANCE OF ADDITIONAL SERIES
The issuance of any additional Series of Certificates is subject to the
following conditions, among others:
(a) appropriate documentation required by the Note Indenture and
Trust Agreement, including supplements thereto, shall have been authorized,
executed and delivered by all parties required to do so by the terms of the
relevant documents;
(b) an Issuance Advice Letter shall have been submitted to the CPUC
and shall have become effective;
(c) the Rating Agency Condition shall have been satisfied with
respect to such issuance;
(d) such issuance will not result in an adverse tax consequence to
the Trust or the Certificateholders;
(e) no Event of Default shall have occurred and be continuing under
the Note Indenture or the Trust Agreement;
(f) as of the date of issuance, the Trust shall have sufficient funds
available to pay the purchase price for the related Series of Notes, and
all conditions to the issuance of a new series of Notes and Certificates
shall have been satisfied or waived; and
(g) delivery by the Note Issuer to the Note Trustee of certain
certificates and opinions specified in the Note Indenture.
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CERTAIN FEDERAL INCOME TAX CONSEQUENCES
Interest on the Certificates will be included in gross income for federal
income tax purposes.
GENERAL
The following is a general discussion of material federal income tax
consequences relating to the purchase, ownership and disposition of a
Certificate, and is based on the opinion of Special Counsel. This discussion
represents the opinion of Special Counsel, subject to the qualifications set
forth therein or herein. Additional federal income tax considerations relevant
to a particular Series may be set forth in the related Prospectus Supplement.
This discussion is based on current provisions of the Internal Revenue Code of
1986, as amended (the "Code"), currently applicable Treasury regulations and
judicial and administrative rulings and decisions. Legislative, judicial or
administrative changes may be forthcoming that could alter or modify the
statements and conclusions set forth herein. Any such changes or
interpretations may or may not be retroactive and could affect tax consequences
to Certificateholders.
The discussion does not address all of the tax consequences relevant to a
particular Certificateholder in light of that Certificateholder's circumstances,
and some Certificateholders may be subject to special tax rules and limitations
not discussed below (e.g., life insurance companies, tax-exempt organizations,
financial institutions or broker-dealers). CONSEQUENTLY, EACH PROSPECTIVE
CERTIFICATEHOLDER IS URGED TO CONSULT ITS OWN TAX ADVISER IN DETERMINING THE
FEDERAL, STATE, LOCAL AND FOREIGN INCOME AND ANY OTHER TAX CONSEQUENCES OF THE
PURCHASE, OWNERSHIP AND DISPOSITION OF A CERTIFICATE.
For purposes of this discussion, "U.S. PERSON" means a citizen or resident
of the United States, a corporation or partnership created or organized in the
United States, or under the law of the United States or of any state thereof
(including the District of Columbia), an estate the income of which is
includible in gross income for U.S. federal income tax purposes regardless of
its source, or a trust if a court within the United States is able to exercise
primary supervision over the administration of the trust and one or more United
States persons has the authority to control all substantial decisions of the
trust (or, under certain circumstances, a trust the income of which is
includible in gross income for U.S federal income tax purposes regardless of its
source). The term "U.S. CERTIFICATEHOLDER" means any U.S. Person and any other
person to the extent that income attributable to its interest in a Certificate
is effectively connected with that person's conduct of a U.S. trade or business.
The term "NON-U.S. CERTIFICATEHOLDER" means any person other than a U.S.
Certificateholder.
The discussion assumes that a Certificate is issued in registered form, has
all payments denominated in U.S. dollars and not determined by reference to the
value of any other currency and has a term that exceeds one year. Moreover, the
discussion assumes that any original issue discount ("OID") on the Certificate
(i.e., any excess of the stated redemption price at maturity of the Certificate
over its issue price) is less than a de minimis amount (i.e., 0.25 percent of
its stated redemption price at maturity multiplied by the Certificate's weighted
average maturity), all within the meaning of the OID regulations. Moreover, the
discussion assumes that the Certificates are of a type, as set forth below,
which Special Counsel is of the opinion will represent ownership of debt for
federal income tax purposes. The applicable Prospectus Supplement will set
forth a discussion of any additional material tax consequences with respect to
Certificates not conforming to the foregoing assumptions.
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TREATMENT OF THE CERTIFICATES AS DEBT
Special Counsel has rendered an opinion to the effect that, for federal
income tax purposes, the Certificates will represent ownership of debt and the
Trust will not be treated as an association or publicly traded partnership
taxable as a corporation.
TAXATION OF INTEREST INCOME OF U.S. CERTIFICATEHOLDERS
General. Assuming, in accordance with Special Counsel's opinion, that the
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Certificates represent ownership of debt obligations for federal income tax
purposes, stated interest on a beneficial interest in a Certificate will be
taxable as ordinary income when received or accrued by U.S. Certificateholders
in accordance with their method of accounting. Generally, interest received on
the Certificates will constitute "investment income" for purposes of certain
limitations of the Code concerning the deductibility of investment interest
expense.
Market Discount. A U.S. Certificateholder who purchases (including a
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purchase at original issuance for a price less than the issue price) an interest
in a Certificate at a discount that exceeds any unamortized OID may be subject
to the "market discount" rules of sections 1276 through 1278 of the Code. These
rules generally provide that, subject to a statutorily-defined de minimis
exception, if a U.S. Certificateholder acquires a Certificate at a market
discount (i.e., at a price below its stated redemption price at maturity or its
revised issue price if it was issued with OID) and thereafter recognizes gain
upon a disposition of the Certificate (or disposes of it in certain non-
recognition transactions, including by gift), the lesser of such gain (or
appreciation, in the case of an applicable non-recognition transaction) or the
portion of the market discount that accrued while the Certificate was held by
such holder will be treated as ordinary interest income at the time of the
disposition. In addition, a U.S. Certificateholder who acquired a Certificate
at a market discount would be required to treat as ordinary interest income the
portion of any principal payment attributable to accrued market discount on such
Certificate. Generally, market discount accrues ratably over the life of a debt
instrument unless the debt holder elects to accrue market discount on a constant
yield to maturity basis. It is not clear how either the ratable accrual or
constant yield accrual methodologies apply to instruments such as the
Certificates where the timing of principal payments is uncertain. Investors
should consult their own tax advisors concerning the accrual of market discount.
The market discount rules also provide that a U.S. Certificateholder who
acquires a Certificate at a market discount may be required to defer a portion
of any interest expense that otherwise may be deductible on any indebtedness
incurred or maintained to purchase or carry the Certificate until the holder
disposes of the Certificate in a taxable transaction.
A U.S. Certificateholder who acquired a Certificate at a market discount
may elect to include market discount in income as the discount accrues, either
on a ratable basis or, if elected, on a constant yield basis. The current
inclusion election, once made, applies to all market discount obligations
acquired on or after the first day of the first taxable year to which the
election applies, and may not be revoked without the consent of the Internal
Revenue Service (the "IRS"). If a holder elects to include market discount in
income in accordance with the preceding sentence, the foregoing rules with
respect to the recognition of ordinary income on sales, principal payments and
certain other dispositions of the Certificates and the deferral of interest
deductions on indebtedness related to the investor certificates will not apply.
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Amortizable Bond Premium. A U.S. Certificateholder who purchases an
------------------------
interest in a Certificate at a premium may elect to offset the premium against
interest income under the constant yield method over the remaining term of the
Certificate in accordance with the provisions of section 171 of the Code. A
holder that elects to amortize bond premium must reduce the tax basis in the
related Certificate by the amount of bond premium used to offset interest
income. If a Certificate purchased at a premium is redeemed in full prior to
its maturity, a holder who has elected to amortize bond premium should be
entitled to a deduction in the taxable year of redemption in an amount equal to
the excess, if any, of the adjusted basis of the Certificate over the greater of
the redemption price or the amount payable on maturity.
SALE OR EXCHANGE OF CERTIFICATES
Upon a disposition of an interest in a Certificate, a U.S.
Certificateholder generally will recognize gain or loss equal to the difference
between (i) the amount of cash and the fair market value of any other property
received (other than amounts attributable to, and taxable as, accrued stated
interest) and (ii) the U.S. Certificateholder's adjusted basis in its interest
in the Certificate. The adjusted basis in the interest in the Certificate will
equal its cost, increased by any OID or market discount included in income with
respect to the interest in the Certificate prior to its disposition and reduced
by any payments reflecting principal or OID previously received with respect to
the interest in the Certificate and any amortized premium. Subject to the OID
and market discount rules, gain or loss will generally be capital gain or loss
if the interest in the Certificate was held as a capital asset. Capital losses
generally may be used by a corporate taxpayer only to offset capital gains and
by an individual taxpayer only to the extent of capital gains plus $3,000 of
other income.
NON-U.S. CERTIFICATEHOLDERS
In general, a non-U.S. Certificateholder will not be subject to U.S.
federal income tax on interest (including OID) on a beneficial interest in a
Certificate unless (i) the non-U.S. Certificateholder actually or constructively
owns 10 percent or more of the total combined voting power of all classes of
stock of the Seller entitled to vote (or of a profits or capital interest of the
Trust characterized as a partnership), (ii) the non-U.S. Certificateholder is a
controlled foreign corporation that is related to the Seller (or the Trust
treated as a partnership) through stock ownership, (iii) the non-U.S.
Certificateholder is a bank which receives interest as described in Code Section
881(c)(3)(A), or (iv) such interest is contingent interest described in Code
Section 871(h)(4). To qualify for the exemption from taxation, the last U.S.
Person in the chain of payment prior to payment to a non-U.S. Certificateholder
(the "WITHHOLDING AGENT") must have received (in the year in which a payment of
interest or principal occurs or in either of the two preceding years) a
statement that (i) is signed by the non-U.S. Certificateholder under penalties
of perjury, (ii) certifies that the non-U.S. Certificateholder is not a U.S.
Person and (iii) provides the name and address of the non-U.S.
Certificateholder. The statement may be made on a Form W-8 or substantially
similar substitute form, and the non-U.S. Certificateholder must inform the
Withholding Agent of any change in the information on the statement within 30
days of the change. If a Certificate is held through a securities clearing
organization or certain other financial institutions, the organization or
institution may provide a signed statement to the Withholding Agent. However,
in that case, the signed statement must be accompanied by a Form W-8 or
substitute form provided by the non-U.S. Certificateholder to the organization
or institution holding the Certificate on behalf of the non-U.S.
Certificateholder. The U.S. Treasury Department is considering implementation
of further certification requirements aimed at determining whether the issuer of
a debt obligation is related to holders thereof.
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Generally, any gain or income realized by a non-U.S. Certificateholder upon
retirement or disposition of an interest in a Certificate (other than gain
attributable to accrued interest or OID, which is addressed in the preceding
paragraph) will not be subject to U.S. federal income tax, provided that in the
case of a Certificateholder that is an individual, such Certificateholder is not
present in the United States for 183 days or more during the taxable year in
which such retirement or disposition occurs. Certain exceptions may be
applicable, and an individual non-U.S. Certificateholder should consult a tax
adviser.
INFORMATION REPORTING AND BACKUP WITHHOLDING
Backup withholding of U.S. federal income tax at a rate of 31 percent may
apply to payments made in respect of a Certificate to a registered owner who is
not an "exempt recipient" and who fails to provide certain identifying
information (such as the registered owner's taxpayer identification number) in
the manner required. Generally, individuals are not exempt recipients whereas
corporations and certain other entities are exempt recipients. Payments made in
respect of a U.S. Certificateholder must be reported to the IRS, unless the U.S.
Certificateholder is an exempt recipient or otherwise establishes an exemption.
In the case of payments of principal of and interest on (and the amount of
OID, if any, accrued on) investor certificates to non-U.S. Certificateholders,
temporary Treasury regulations provide that backup withholding and information
reporting will not apply to payments with respect to which either requisite
certification has been received or an exemption has otherwise been established
(provided that neither the Certificate Trustee nor a paying agent has actual
knowledge that the holder is a U.S. Person or that the conditions of any other
exemption are not in fact satisfied). Payments of the proceeds of the sale of a
Certificate to or through a foreign office of a broker that is a U.S. Person, a
controlled foreign corporation for United States federal income tax purposes or
a foreign person 50% or more of whose gross income is effectively connected with
the conduct of a trade or business within the United States for a specified
three-year period are currently subject to certain information reporting
requirements, unless the payee is an exempt recipient or such broker has
evidence in its records that the payee is not a U.S. Person and no actual
knowledge that such evidence is false and certain other conditions are met.
Temporary Treasury regulations indicate that such payments are not currently
subject to backup withholding. Under current Treasury regulations, payments of
the proceeds of a sale to or through the United States office of a broker will
be subject to information reporting and backup withholding unless the payee
certifies under penalties of perjury as to his or her status as a non-U.S.
Person and certain other qualifications (and no agent of the broker who is
responsible for receiving or reviewing such statement has actual knowledged that
it is incorrect) and provides his or her name and address or the payee otherwise
establishes an exemption.
Any amounts withheld under the backup withholding rules from a payment to a
Certificateholder would be allowed as a refund or a credit against such
Certificateholder's U.S. federal income tax, provided that the required
information is furnished to the IRS.
STATE TAXATION
CALIFORNIA TAXATION
In the opinion of Special Counsel, interest and OID on the Certificates
will be exempt from California personal income tax, but not exempt from the
California franchise tax applicable to banks and corporations. Gain or loss, if
any, resulting from an exchange or redemption of Certificates will be recognized
in the year of the exchange or redemption. Present California law taxes both
long-term and short-term capital gains at the rates applicable to ordinary
income. Interest on indebtedness incurred or continued by a Certificateholder
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in connection with the purchase of Certificates will not be deductible for
California personal income tax purposes.
OTHER STATES
The discussion above does not address the taxation of the Trust or the tax
consequences of the purchase, ownership or disposition of an interest in the
Certificates under any state or local tax law other than that of the State of
California. Each investor should consult its own tax adviser regarding state
and local tax consequences.
ERISA CONSIDERATIONS
ERISA and/or Section 4975 of the Code impose certain requirements on
employee benefit plans and certain other plans and arrangements, including
individual retirement accounts and annuities, Keogh plans and certain collective
investment funds or insurance company general or separate accounts in which such
plans, accounts or arrangements are invested, that are subject to the fiduciary
responsibility and prohibited transaction provisions of ERISA and/or Section
4975 of the Code (collectively, "PLANS"), and on persons who are fiduciaries
with respect to Plans, in connection with the investment of assets that are
treated as "plan assets" of any Plan for purposes of applying Title I of ERISA
and Section 4975 of the Code ("PLAN ASSETS"). ERISA imposes on Plan fiduciaries
certain general fiduciary requirements, including those of investment prudence
and diversification and the requirement that a Plan's investments be made in
accordance with the documents governing the Plan. Generally, any person who has
discretionary authority or control respecting the management or disposition of
Plan Assets, and any person who provides investment advice with respect to Plan
Assets for a fee or other consideration, is a fiduciary with respect to such
Plan Assets.
ERISA and Section 4975 of the Code prohibit a broad range of transactions
involving Plan Assets and persons who have certain specified relationships to a
Plan or its Plan Assets ("parties in interest" under ERISA and "disqualified
persons" under the Code (collectively, "PARTIES IN INTEREST")), unless a
statutory or administrative exemption is available. Parties in Interest and
Plan fiduciaries that participate in a prohibited transaction may be subject to
penalties imposed under ERISA and/or excise taxes imposed pursuant to Section
4975 of the Code, unless a statutory or administrative exemption is available.
These prohibited transactions generally are set forth in Section 406 of ERISA
and Section 4975 of the Code.
Any fiduciary or other Plan investor considering whether to purchase the
Certificates of any Class or Series on behalf or with Plan Assets of any Plan
should consult with its legal advisors and refer to the related Prospectus
Supplement for guidance regarding the ERISA Considerations applicable to the
Certificates offered thereby.
Certain employee benefit plans, such as governmental plans (as defined in
Section 3(32) of ERISA) and certain church plans (as defined in Section 3(33) of
ERISA), are not subject to the requirements of ERISA or Section 4975 of the
Code. Accordingly, except as provided in the applicable Prospectus Supplement,
assets of such plans may be invested in the Certificates of any Class or Series
without regard to the ERISA considerations described herein, subject to the
provisions of other applicable federal and state law. However, any such plan
that is qualified and exempt from taxation under Sections 401(a) and 501(a) of
the Code is subject to the prohibited transaction rules set forth in Section 503
of the Code.
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USE OF PROCEEDS
The Trust will use the net proceeds received from each sale of a Series of
Certificates to purchase the related Note or Notes from the Note Issuer. The
Note Issuer will use such proceeds to purchase the Transition Property from the
Seller and to pay issuance costs related to the Notes. The Seller will use such
proceeds to repay outstanding debt and reduce the amount of outstanding equity
generally in proportion to its existing capital structure.
PLAN OF DISTRIBUTION
The Certificates of each Series may be sold to or through underwriters
named in the related Prospectus Supplement (the "UNDERWRITERS") by a negotiated
firm commitment underwriting and public reoffering by the Underwriters or such
other underwriting arrangement as may be specified in the related Prospectus
Supplement or may be offered or placed either directly or through agents. The
Note Issuer and the Trust intend that Certificates will be offered through such
various methods from time to time and that offerings may be made concurrently
through more than one of such methods or that an offering of a particular Series
of Certificates may be made through a combination of such methods.
The distribution of Certificates may be effected from time to time in one
or more transactions at a fixed price or prices, which may be changed, or at
market prices prevailing at the time of sale, at prices related to such
prevailing market prices or in negotiated transactions or otherwise at varying
prices to be determined at the time of sale.
In connection with the sale of the Certificates, Underwriters or agents may
receive compensation in the form of discounts, concessions or commissions.
Underwriters may sell Certificates to certain dealers at prices less a
concession. Underwriters may allow and such dealers may reallow a concession to
certain other dealers. Underwriters, dealers and agents that participate in the
distribution of the Certificates of a Series may be deemed to be underwriters
and any discounts or commissions received by them from the Trust and any profit
on the resale of the Certificates by them may be deemed to be underwriting
discounts and commissions under the Securities Act. Any such Underwriters or
agents will be identified, and any such compensation received from the Trust
will be described, in the related Prospectus Supplement.
Under agreements which may be entered into by the Seller, the Note Issuer
and the Trust, Underwriters and agents who participate in the distribution of
the Certificates may be entitled to indemnification by the Seller and the Note
Issuer against certain liabilities, including liabilities under the Securities
Act.
The Underwriters may, from time to time, buy and sell Certificates, but
there can be no assurance that an active secondary market will develop and there
is no assurance that any such market, if established, will continue.
RATINGS
It is a condition of issuance of each Class of Certificates that at the
time of issuance such Class receive the rating indicated in the related
Prospectus Supplement, which will be in one of the four highest categories, from
at least one Rating Agency. Each Class of Notes will receive the same rating
from the applicable Rating Agencies as the corresponding Class of Certificates.
A security rating is not a recommendation to buy, sell or hold securities
and may be subject to revision or withdrawal at any time by the assigning Rating
Agency. No person is obligated to maintain the rating on any Certificate, and,
accordingly, there can be no assurance that the ratings assigned to any Class of
Certificates upon initial issuance will not be lowered or withdrawn by a Rating
Agency at any time thereafter. If a rating of any Class of Certificates is
86
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revised or withdrawn, the liquidity of such Class of Certificates may be
adversely affected. In general, ratings address credit risk and do not
represent any assessment of the rate of FTA Collections.
LEGAL MATTERS
Certain legal matters relating to the Notes and certain federal income tax
consequences of the issuance of the Notes will be passed upon by Orrick,
Herrington & Sutcliffe LLP, San Francisco, California, counsel to the Seller and
the Note Issuer. Certain legal matters relating to the Certificates and certain
federal income tax consequences of the issuance of the Certificates will be
passed upon by Brown & Wood LLP, San Francisco, California, counsel to the
Trust. Certain legal matters relating to the Certificates will be passed upon
by Cravath, Swaine & Moore, New York, New York, counsel to the Underwriters.
87
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INDEX OF PRINCIPAL DEFINITIONS
------------------------------
<TABLE>
<S> <C>
Act................................................................. 40
Actual FTA Payments................................................. 49
Administrator....................................................... 19
Advice Letters...................................................... 13
Annual Accountant's Report.......................................... 50
Base Calculation Model.............................................. 35
Basic Documents..................................................... 61
Billing Period...................................................... 19
Book-Entry Certificates............................................. 21
Calculation Date.................................................... 36
Capital Subaccount.................................................. 17, 56
Cede................................................................ 21
CEDEL............................................................... 69
CEDEL Participants.................................................. 71
Certificate Account................................................. 64
Certificate Business Day............................................ 65
Certificate Event of Default........................................ 17, 65
Certificate Trustee................................................. 9
Certificateholders.................................................. 3
Certificates........................................................ 1, 9
Class............................................................... 1, 9
Closing Date........................................................ 37
Code................................................................ 22
Collection Account.................................................. 54
Collections Curve................................................... 48
Commission.......................................................... 3
Cooperative......................................................... 71
CPUC................................................................ 11
Customers........................................................... 12
Default............................................................. 66
Definitive Certificates............................................. 72
Delaware Business Trust Act......................................... 30
Delaware Trustee.................................................... 9
Depositaries........................................................ 69
Distribution Date................................................... 15
DRI................................................................. 43
DTC................................................................. 3, 21
Eligible Institution................................................ 54
Eligible Investments................................................ 54
ERISA............................................................... 22
ESPs................................................................ 26
Estimated FTA Payments.............................................. 48
Euroclear........................................................... 69
Euroclear Operator.................................................. 71
Euroclear Participants.............................................. 71
Event of Default.................................................... 17
Excess Remittance................................................... 49
Exchange Act........................................................ 3
Expected Amortization Schedule...................................... 16
FDIC................................................................ 54
Fee Agreement....................................................... 40
FERC................................................................ 27
Final Maturity Date................................................. 53
Financing Order..................................................... 12
Financing Order Anniversary......................................... 37
FTA Charge.......................................................... 12
FTA Collections..................................................... 13
FTA Payments........................................................ 13
General Subaccount.................................................. 17
H.R. 1230........................................................... 24
</TABLE>
88
<PAGE>
<TABLE>
<S> <C>
Indirect Participants............................................... 21
Infrastructure Bank................................................. 1, 8
Initial Transition Property......................................... 37
IRS................................................................. 74, 75
ISO................................................................. 27
Issuance Advice Letter.............................................. 13
Monthly Servicer's Certificate...................................... 50
Moody's............................................................. 29
Non-U.S. Certificateholder.......................................... 74
Note Collateral..................................................... 54
Note Event of Default............................................... 17, 59
Note Indenture...................................................... 53
Note Interest Rate.................................................. 53
Note Issuer......................................................... 1, 8
Note Trustee........................................................ 11
Noteholder.......................................................... 53
Notes............................................................... 1, 7
OID................................................................. 74
Operating Expenses.................................................. 19
Overcollateralization Amount........................................ 55
Overcollateralization Subaccount.................................... 17, 56
Participants........................................................ 21
Parties in Interest................................................. 78
Payment Date........................................................ 15
PG&E................................................................ 1, 8
Plan Assets......................................................... 77
Plans............................................................... 77
Proposition 218..................................................... 24
PU Code............................................................. 11
PX.................................................................. 27
Quarterly Administration Fee........................................ 58
Quarterly Interest.................................................. 58
Quarterly Overcollateralization Collection.......................... 55
Quarterly Principal................................................. 58
Quarterly Servicer's Certificate.................................... 62
Rate Freeze Period.................................................. 34
Rating Agency....................................................... 21
Rating Agency Condition............................................. 53
Record Date......................................................... 15
Registration Statement.............................................. 3
Remittance Date..................................................... 49
Remittance Shortfall................................................ 49
Required Capital Level.............................................. 18
Reserve Subaccount.................................................. 17
Residential Customers............................................... 12
Rules............................................................... 70
S&P................................................................. 29
Sale Agreement...................................................... 8
Scheduled Final Distribution Date................................... 15
Scheduled Maturity Date............................................. 53
Securities Act...................................................... 3
Seller.............................................................. 1, 8
Series.............................................................. 1, 9
Series Issuance Date................................................ 53
Servicer............................................................ 1, 8
Servicer Business Day............................................... 45
Servicer Defaults................................................... 51
Servicing Agreement................................................. 8
Servicing Fee....................................................... 20
Small Commercial Customers.......................................... 12
Special Counsel..................................................... 24
Special Distribution Date........................................... 64
Special Payments.................................................... 64
State Pledge........................................................ 14, 63
Statute............................................................. 7
</TABLE>
89
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<TABLE>
<S> <C>
Subsequent Transfer Date............................................ 37
Subsequent Transition Property...................................... 37
Swap Agreement...................................................... 7
Termination Date.................................................... 15
Terms and Conditions................................................ 72
Territory........................................................... 12
Transition Costs.................................................... 11
Transition Property................................................. 13
True-Up Mechanism Advice Letter..................................... 14
True-Up Mechanism Calculation Model................................. 36
Trust............................................................... 1, 8
Trust Agreement..................................................... 8
U.S. Certificateholder.............................................. 74
U.S. Person......................................................... 74
Underwriters........................................................ 78
Utilities........................................................... 7
Withholding Agent................................................... 76
</TABLE>
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================================================================================
NO DEALER, SALESPERSON OR OTHER PERSON HAS BEEN AUTHORIZED TO GIVE ANY
INFORMATION OR TO MAKE ANY REPRESENTATIONS OTHER THAN THOSE CONTAINED IN THIS
PROSPECTUS SUPPLEMENT AND THE PROSPECTUS AND, IF GIVEN OR MADE, SUCH INFORMATION
OR REPRESENTATIONS MUST NOT BE RELIED UPON AS HAVING BEEN AUTHORIZED BY THE
SELLER, THE NOTE ISSUER, THE TRUST, THE INFRASTRUCTURE BANK, THE UNDERWRITERS OR
ANY DEALER, SALESPERSON OR OTHER PERSON. NEITHER THE DELIVERY OF THIS
PROSPECTUS SUPPLEMENT AND THE PROSPECTUS NOR ANY SALE MADE HEREUNDER SHALL,
UNDER ANY CIRCUMSTANCES, CREATE AN IMPLICATION THAT INFORMATION HEREIN OR
THEREIN IS CORRECT AS OF ANY TIME SINCE THE DATE OF THIS PROSPECTUS SUPPLEMENT
OR THE PROSPECTUS. THIS PROSPECTUS SUPPLEMENT AND THE PROSPECTUS DO NOT
CONSTITUTE AN OFFER TO SELL, OR A SOLICITATION OF AN OFFER TO BUY ANY SECURITY
IN ANY JURISDICTION IN WHICH IT IS UNLAWFUL TO MAKE ANY SUCH OFFER OR
SOLICITATION.
-------------------
TABLE OF CONTENTS
PROSPECTUS SUPPLEMENT
<TABLE>
<CAPTION>
Page
----
<S> <C>
REPORTS TO HOLDERS.............................................. S-4
PROSPECTUS SUPPLEMENT SUMMARY................................... S-5
ADDITIONAL RISK FACTORS RELATING TO THE CLASS
CERTIFICATES.................................................... S-14
DESCRIPTION OF THE CERTIFICATES................................. S-14
SUMMARY OF CERTAIN PROVISIONS OF THE SERIES
SUPPLEMENT TO THE TRUST AGREEMENT............................... S-17
[SUMMARY OF CERTAIN PROVISIONS OF THE SWAP
AGREEMENT]...................................................... S-17
[THE SWAP COUNTERPARTY]......................................... S-17
DESCRIPTION OF THE NOTES........................................ S-17
DESCRIPTION OF THE TRANSITION PROPERTY.......................... S-20
CERTAIN DISTRIBUTION AND WEIGHTED AVERAGE LIFE
CONSIDERATIONS.................................................. S-21
THE SELLER AND SERVICER......................................... S-22
SERVICING....................................................... S-22
CERTAIN FEDERAL INCOME TAX CONSEQUENCES......................... S-24
STATE TAXATION.................................................. S-27
ERISA CONSIDERATIONS............................................ S-28
UNDERWRITING.................................................... S-30
RATINGS......................................................... S-30
LEGAL MATTERS................................................... S-31
INDEX OF PRINCIPAL DEFINITIONS.................................. S-32
FINANCIAL STATEMENTS............................................ F-1
</TABLE>
PROSPECTUS
<TABLE>
<S> <C>
AVAILABLE INFORMATION.............................................
REPORTS TO HOLDERS................................................
INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE...................
PROSPECTUS SUPPLEMENT.............................................
PROSPECTUS SUMMARY................................................
RISK FACTORS......................................................
ENERGY DEREGULATION AND NEW CALIFORNIA
MARKET STRUCTURE.................................................
DESCRIPTION OF THE TRANSITION PROPERTY............................
CERTAIN DISTRIBUTION AND WEIGHTED AVERAGE LIFE
CONSIDERATIONS...................................................
THE TRUST.........................................................
THE INFRASTRUCTURE BANK...........................................
THE NOTE ISSUER...................................................
THE SELLER AND SERVICER...........................................
SERVICING.........................................................
DESCRIPTION OF THE NOTES..........................................
DESCRIPTION OF THE CERTIFICATES...................................
CERTAIN FEDERAL INCOME TAX CONSEQUENCES...........................
STATE TAXATION....................................................
ERISA CONSIDERATIONS..............................................
USE OF PROCEEDS...................................................
PLAN OF DISTRIBUTION..............................................
RATINGS...........................................................
LEGAL MATTERS.....................................................
INDEX OF PRINCIPAL DEFINITIONS....................................
</TABLE>
CALIFORNIA
INFRASTRUCTURE AND
ECONOMIC DEVELOPMENT BANK
SPECIAL PURPOSE
TRUST PG&E-1
$_______________
RATE REDUCTION CERTIFICATES
SERIES 199_-__
----------------------------
PROSPECTUS SUPPLEMENT
----------------------------
[NAME OF UNDERWRITER(S)]
_______, 199__
================================================================================
<PAGE>
PART II
ITEM 14. Other Expenses of Issuance and Distribution.
The following is an itemized list of the estimated expenses to be incurred
in connection with the offering of the securities being offered hereunder other
than underwriting discounts and commissions.
<TABLE>
<CAPTION>
<S> <C>
Registration Statement Fee...................... $303.03
Printing and Engraving Expenses................. *
Trustees' Fees and Expenses..................... *
Legal Fees and Expenses......................... *
Blue Sky Fees and Expenses...................... *
Accountants' Fees and Expenses.................. *
Rating Agency Fees.............................. *
Miscellaneous Fees and Expenses................. *.
-------
Total....................................... $ *.
=======
</TABLE>
___________________
* To be filed by amendment.
ITEM 15. Indemnification of Directors and Officers.
Section 18-108 of the Delaware Limited Liability Company Act provides that
subject to such standards and restrictions, if any, as are set forth in its
limited liability company agreement, a limited liability company may and has the
power to indemnify and hold harmless any member or other person from and against
any and all claims and demands whatsoever. Section 17 of the Limited Liability
Company Agreement of the Registrant provides that, to the full extent permitted
by applicable law, the Registrant shall indemnify any member or officer of the
Registrant for any loss, damage or claim incurred by such member or officer by
reason of any act or omission performed or omitted in good faith on behalf of
the Registrant in a manner reasonably believed to be within the scope of the
authority conferred on such member or officer by the Limited Liability Company
Agreement, except that the Registrant shall not indemnify any such member or
officer for any loss, act or omission incurred by such member or officer by
reason of willful misconduct with respect to such acts or omissions.
Section 317 of the California Corporation Law (the "California Law")
provides that a corporation shall have the power to indemnify any person who was
or is a party or is threatened to be made a party to any proceeding or action by
reason of the fact that he or she is or was a director, officer, employee or
other agent of such corporation. Section 317 also grants authority to a
corporation to include in its articles of incorporation indemnification
provisions in excess of that permitted in Section 317, subject to certain
limitations.
Article SIXTH of the Articles of Incorporation of Pacific Gas and Electric
Company (the "Member") authorizes the Member to provide indemnification of
directors and officers through bylaws, resolutions, agreements with agents, vote
of shareholders or disinterested directors, or otherwise, in excess of the
indemnification otherwise permitted by Section 317 of the California Law,
subject only to the applicable limits set forth in Section 204 of the California
Law. The Registrant believes that the officers of the Registrant are serving at
the request of the Member and are therefore entitled to such indemnity from the
Member.
II-1
<PAGE>
The Board of Directors of the Member has adopted a resolution implementing
the authority granted in Article SIXTH of the Articles of Incorporation. The
resolution provides for the indemnification of any director and officer of the
Member for any threatened, pending or completed action, suit or proceeding to
the fullest extent permissible under California Law and the Articles of
Incorporation, subject to the terms of any agreement between the Member and such
a person; provided that, no such person shall be indemnified: (i) except to the
extent that the aggregate of losses to be indemnified exceeds the amount of such
losses for which the director or officer is paid pursuant to any director's or
officer's liability insurance policy maintained by the Member; (ii) for any suit
or judgment resulting from an accounting of profits made through the purchase or
sale of securities of the Member pursuant to Section 16(b) of the Securities
Exchange Act of 1934; (iii) if a court of competent jurisdiction determines that
the indemnification is unlawful; (iv) for any acts or omissions involving
intentional misconduct or knowing and culpable violation of law; (v) for acts or
omissions that the director or officer believes to be contrary to the best
interests of the Member or its shareholders, or that involve the absence of good
faith; (vi) for any transaction from which the director or officer derived an
improper personal benefit; (vii) for acts or omissions that show a reckless
disregard for the director's or officer's duty to the Member or its shareholders
in circumstances in which the director or officer was aware, or should have been
aware, in the ordinary course of performing his or her duties, of a risk of
serious injury to the Member or its shareholders; (viii) for acts or omissions
that constitute an unexcused pattern of inattention that amount to an abdication
of the director's or officer's duties to the Member or its shareholders; (ix)
for costs, charges, expenses, liabilities and losses arising under Section 310
or 316 of the California Law; or (x) as to circumstances in which indemnity is
expressly prohibited by Section 317. The exclusions set forth in clauses (iv)
through (x) above shall apply only to indemnification for acts, omissions or
transactions involving breach of duty to the Member or its shareholders. The
resolution also provides that the Member shall indemnify any director or officer
in connection with (a) a proceeding (or part thereof) initiated by him or her
only if such proceeding (or part thereof) was authorized by the Board of
Directors or (b) a proceeding (or part thereof), other than a proceeding by or
in the name of the Member to procure a judgment in its favor, only if any
settlement of such a proceeding is approved in writing by the Member.
Indemnification shall cover all costs, charges, expenses, liabilities and
losses, including, without limitation, attorneys' fees, judgments, fines, ERISA
excise taxes, or penalties and amounts paid or to be paid in settlement,
reasonably incurred or suffered by the director or officer.
The Member has directors' and officers' liability insurance policies in
force insuring directors and officers of the Member and its subsidiaries.
II-2
<PAGE>
<TABLE>
<CAPTION>
ITEM 16. Exhibits.
<S> <C>
*1.1 Form of Underwriting Agreement.
+3.1 Certificate of Formation.
+3.2 Limited Liability Company Agreement.
*4.1 Form of Note Indenture.
*4.2 Form of Trust Agreement.
*4.3 Form of Note.
*4.4 Form of Rate Reduction Certificate.
*5.1 Opinion of Orrick, Herrington & Sutcliffe LLP with respect to legality
of the Notes.
*5.2 Opinion of Brown & Wood LLP with respect to legality of the Rate
Reduction Certificates.
*8.1 Opinion of Brown & Wood LLP with respect to tax matters.
*10.1 Form of Transition Property Purchase and Sale Agreement.
*10.2 Form of Transition Property Servicing Agreement.
*10.3 Form of Note Purchase Agreement.
*10.4 Form of Fee and Indemnity Agreement.
*23.1 Consent of Orrick, Herrington & Sutcliffe LLP (included in its opinion
filed as Exhibit 5.1).
*23.2 Consents of Brown & Wood LLP (included in its opinions filed as
Exhibits 5.2 and 8.1).
99.1 Application for Financing Order.
*99.2 Financing Order.
*99.3 Form of Issuance Advice Letter.
*99.4 Application to Infrastructure Bank.
*99.5 Order of Infrastructure Bank.
</TABLE>
__________
*To be filed by amendment.
+Previously filed.
ITEM 17. UNDERTAKINGS.
The undersigned Registrant on behalf of the California Infrastructure and
Economic Development Bank Special Purpose Trust PG&E-1 (the "Trust") hereby
undertakes as follows:
(a) (1) To file, during any period in which offers or sales are being
made, a post-effective amendment to this Registration Statement; (i) to include
any prospectus required by Section 10(a)(3) of the Securities Act of 1933; (ii)
to reflect in the prospectus any facts or events arising after the effective
date of the Registration Statement (or the most recent post-effective amendment
thereof) which, individually or in the aggregate, represent a fundamental change
in the information set forth in the Registration Statement (Notwithstanding the
foregoing, any increase or decrease in volume of securities offered (if the
total dollar value of securities offered would not exceed that which was
registered) and any deviation from the low or high end of the estimated maximum
offering range may be reflected in the form of prospectus filed with the
Commission pursuant to Rule 424(b) if, in the aggregate, the changes in volume
and price represent no more than a 20% change in the maximum aggregate offering
price set forth in the "Calculation of Registration Fee" table in the effective
Registration Statement.); (iii) to include any material information with respect
to the plan of distribution not previously disclosed in the Registration
Statement or any material change to such information in the Registration
Statement; provided, however, that (a)(1)(i) and (a)(1)(ii) will not apply if
the information required to be included in a post-effective amendment by those
paragraphs is contained in periodic reports filed pursuant to Section 13 or
Section 15(d) of the Securities Exchange Act of 1934 that are incorporated by
reference in this Registration Statement.
II-3
<PAGE>
(2) That, for the purpose of determining any liability under the
Securities Act of 1933, each such post-effective amendment shall be deemed to be
a new Registration Statement relating to the securities offered therein, and the
offering of such securities at that time shall be deemed to be the initial bona
fide offering hereof.
(3) To remove from registration by means of a post-effective amendment
any of the securities being registered which remain unsold at the termination of
the offering.
(b) That, for purposes of determining any liability under the Securities Act
of 1933, each filing of the Registrant's annual report pursuant to Section 13(a)
or 15(d) of the Securities Exchange Act of 1934 (and, where applicable, each
filing of an employee benefit plan's annual report pursuant to Section 15(d) of
the Securities Exchange Act of 1934), with respect to the Trust that is
incorporated by reference in the Registration Statement shall be deemed to be a
new registration statement relating to the securities offered therein, and the
offering of such securities at that time shall be deemed to be the initial bona
fide offering thereof.
(c) That insofar as indemnification for liabilities arising under the
Securities Act of 1933 may be permitted to directors, officers and controlling
persons of the Registrant pursuant to the provisions described under Item 15
above, or otherwise, the Registrant has been advised that in the opinion of the
Securities and Exchange Commission such indemnification is against public policy
as expressed in the Securities Act of 1933 and is, therefore, unenforceable. In
the event that a claim for indemnification against such liabilities (other than
the payment by the Registrant of expenses incurred or paid by a director,
officer or controlling person of the Registrant in the successful defense of any
action, suit or proceeding) is asserted by such director, officer or controlling
person in connection with the securities being registered, the Registrant will,
unless in the opinion of its counsel the matter has been settled by controlling
precedent, submit to a court of appropriate jurisdiction the question whether
such indemnification by it is against public policy as expressed in the
Securities Act of 1933 and will be governed by the final adjudication of each
issue.
(d) The undersigned registrant hereby undertakes to file an application for
the purpose of determining the eligibility of the trustee to act under
subsection (a) of Section 310 of the Trust Indenture Act in accordance with the
rules and regulations prescribed by the Commission under Section 305(b)(2) of
the Act.
II-4
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, the Registrant
certifies that it has reasonable grounds to believe that it meets all of the
requirements for filing on Form S-3 and has duly caused this Amendment No. 1 to
Registration Statement to be signed on its behalf by the undersigned, thereunto
duly authorized, in the City of San Francisco, State of California, on September
17, 1997.
PG&E FUNDING LLC
as Registrant
By: /s/ Kent M. Harvey
------------------------------------------
Name: Kent M. Harvey
Title: President
Pursuant to the requirements of the Securities Act of 1933, this Amendment
No. 1 to Registration Statement has been signed on September 17, 1997 by the
following persons in the capacities indicated.
Signature Title
--------- -----
Pacific Gas and Electric Company, Member
as Member
By: /s/ Kent M. Harvey
--------------------------------
Kent M. Harvey
Senior Vice President, Treasurer
and Chief Financial Officer
/s/ Kent M. Harvey President
-------------------------------------- (Principal Executive Officer)
Kent M. Harvey
/s/ Gabriel B. Togneri Treasurer
-------------------------------------- (Principal Financial Officer)
Gabriel B. Togneri
/s/ Christopher P. Johns Controller
-------------------------------------- (Principal Accounting Officer)
Christopher P. Johns
II-5
<PAGE>
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
Sequentially
Exhibit Numbered
Number Description Page
- ------ ----------- ----
<S> <C>
*1.1 Form of Underwriting Agreement.
+3.1 Certificate of Formation.
+3.2 Limited Liability Company Agreement.
*4.1 Form of Note Indenture.
*4.2 Form of Trust Agreement.
*4.3 Form of Note.
*4.4 Form of Rate Reduction Certificate.
*5.1 Opinion of Orrick, Herrington & Sutcliffe LLP with respect
to legality of the Notes.
*5.2 Opinion of Brown & Wood LLP with respect to legality of
the Rate Reduction Certificates.
*8.1 Opinion of Brown & Wood LLP with respect to tax matters.
*10.1 Form of Transition Property Purchase and Sale Agreement.
*10.2 Form of Transition Property Servicing Agreement.
*10.3 Form of Note Purchase Agreement.
*10.4 Form of Fee and Indemnity Agreement.
*23.1 Consent of Orrick, Herrington & Sutcliffe LLP (included in its
opinion filed as Exhibit 5.1).
*23.2 Consents of Brown & Wood LLP (included in its opinions filed as
Exhibits 5.2 and 8.1).
99.1 Application for Financing Order.
*99.2 Financing Order.
*99.3 Form of Issuance Advice Letter.
*99.4 Application to Infrastructure Bank.
*99.5 Order of Infrastructure Bank.
</TABLE>
__________
*To be filed by amendment.
+Previously filed.
II-6
<PAGE>
EXHIBIT 99.1
BEFORE THE PUBLIC UTILITIES COMMISSION
OF THE STATE OF CALIFORNIA
In The Matter Of The Application Of Pacific Gas And
Electric Company For:
(1) Authority To Reduce Rates Effective January 1,
1998; (2) Authority To Sell Or Assign Transition
Property To One Or More Financing Entities; (3) Application No.
Authority To Service Rate Reduction Bonds On Behalf Of
Financing Entities; (4) Authority To Establish Charges
Sufficient To Recover Fixed Transition Amounts; and
(5) Such Further Authority Necessary For PG&E to Carry
Out The Transactions Described In This Application
(U 39 E)
- --------------------------------------------------------
APPLICATION
MICHELLE L. WILSON
MARK R. HUFFMAN
Law Department
Pacific Gas and Electric Company
Post Office Box 7442
San Francisco, CA 94120
Telephone: (415) 973-7497
Attorneys for
PACIFIC GAS AND ELECTRIC COMPANY
May 6, 1997
<PAGE>
<TABLE>
<CAPTION>
TABLE OF CONTENTS
PAGE
<S> <C>
I. INTRODUCTION..............................................................................1
II. SUMMARY OF APPLICATION....................................................................2
A. Electric Industry Restructuring And The Role Of Rate Reduction Bonds...................2
B. The Timing and Size Of The Rate Reduction Bond Issuance................................4
C. Proposed Structure Of The Rate Reduction Bond Transaction..............................4
D. Factors To Be Addressed To Enhance The Rate Reduction Bonds' Credit Rating, Thereby
Maximizing Ratepayer Benefits..........................................................6
1. Bankruptcy Considerations..........................................................6
2. The FTA True-Up Mechanism..........................................................7
3. Overcollateralization and Other Forms of Credit Enhancement........................7
4. Rate Reduction Bond Servicing......................................................8
5. Legislative and Regulatory Risk....................................................8
E. Revenue Requirement And Ratemaking Mechanisms..........................................9
III. RATE PROPOSAL.............................................................................9
IV. RECOMMENDED SCHEDULE.....................................................................10
V. GENERAL INFORMATION......................................................................11
A. Statutory And Regulatory Authority (Rule 15)..........................................11
B. Legal Name And Principal Place Of Business (Rule 15(a))...............................11
C. Correspondence And Communication Regarding The Application (Rule 15(b))...............12
D. Articles of Incorporation (Rule 16(a))................................................12
E. Balance Sheet And Income Statements (Rule 23(a))......................................12
F. Present And Proposed Rates (Rules 23(b) And 23(c))....................................12
G. Property And Equipment (Rule 23(d))...................................................12
H. Rate Of Return Summary (Rules 23(e) and 23(f))........................................13
I. Showing (Rule 23(g))..................................................................13
J. Depreciation Deduction For Federal Income Tax (Rule 23(h))............................13
K. Proxy Statement (Rule 23(i))..........................................................13
L. Service Of Application (Rule 24)......................................................13
M. Form Of Financing Order (Rule 2, Financing Order Rules)...............................14
VI. CONCLUSION...............................................................................14
A. General Authorization.................................................................14
B. The Fixed Transition Amounts And The FTA Charges......................................15
C. The FTA Charges True-up Mechanism.....................................................16
</TABLE>
-i-
<PAGE>
<TABLE>
<S> <C>
D. Transition Property...................................................................17
E. Steps In The Rate Reduction Bond Transaction..........................................17
1. Transfer of Transition Property to the SPE........................................17
2. Transfer of SPE Debt Securities to the Issuer.....................................18
3. Issuance of the Rate Reduction Bonds..............................................18
F. Rate Reduction Bond Servicing.........................................................19
G. Rate Reduction Authorization..........................................................20
H. Ratemaking Mechanism Authorizations...................................................20
I. Additional Authorizations And Approvals...............................................20
</TABLE>
-ii-
<PAGE>
BEFORE THE PUBLIC UTILITIES COMMISSION
OF THE STATE OF CALIFORNIA
In The Matter Of The Application Of Pacific Gas And
Electric Company For:
(1) Authority To Reduce Rates Effective January 1,
1998; (2) Authority To Sell Or Assign Transition
Property To One Or More Financing Entities; (3) Application No.
Authority To Service Rate Reduction Bonds On Behalf Of
Financing Entities; (4) Authority To Establish Charges
Sufficient To Recover Fixed Transition Amounts; and
(5) Such Further Authority Necessary For PG&E to Carry
Out The Transactions Described In This Application
(U 39 E)
- --------------------------------------------------------
APPLICATION
I. INTRODUCTION
Pacific Gas and Electric Company (PG&E) is filing this application as a
part of the ongoing electric industry restructuring (OIR/OII 94-04-031/94-04-
032) initiated by the California Public Utilities Commission (Commission), and
in response to the mandates of Assembly Bill 1890 (AB 1890), signed into law on
September 23, 1996 (1996 Cal. Stat. ch. 854).
The purpose of this application (including the accompanying Supporting
Testimony) is to obtain from the Commission a Financing Order authorizing the
issuance of Rate Reduction Bonds in an aggregate principal amount of up to $3.5
billion. This application also seeks approval, conditioned on timely and
sufficient issuance of the Rate Reduction Bonds, of a 10 percent rate reduction
for all electric residential and small commercial customers./1/ PG&E seeks these
authorizations in order to satisfy the requirements of AB 1890 (Public Utilities
Code Division 1, Part 1, Chapter 4, Article 5.5, ss.ss. 840 et seq.).
--------
/1/ Residential and small commercial customers are defined for the purpose of
this application consistent with their definition in AB 1890. AB 1890
defines small commercial customers to be all those commercial customers
with maximum peak demand of less than 20 kW (Public Utilities Code
ss.331(h)).
-1-
<PAGE>
The issuance of Rate Reduction Bonds will support the 10 percent rate
reduction for residential and small commercial customers by lowering the
carrying costs on a portion of PG&E's transition costs and by spreading out the
recovery over the life of the Bonds. PG&E estimates that the net present value
benefits to its residential and small commercial customers from the issuance of
Rate Reduction Bonds and the associated 10 percent rate reduction will total
approximately $470 million.
Satisfactory and timely Commission approval of this application will enable
the issuance of Rate Reduction Bonds in the fourth quarter of this year and the
implementation of the rate reduction on January 1, 1998.
II. SUMMARY OF APPLICATION
A. ELECTRIC INDUSTRY RESTRUCTURING AND THE ROLE OF RATE REDUCTION BONDS
The issuance of Rate Reduction Bonds is an integral component of
electric industry restructuring in California, which was initiated by the
Commission on April 20, 1994.
On December 20, 1995, the Commission issued its Preferred Policy Decision
(D. 95-12-063, as modified by D. 96-01-009), setting forth its goal to reduce
the costs of electricity to California ratepayers by encouraging competition.
The Preferred Policy Decision also addressed the issue of transition
costs./2/ The Commission determined that:
To assure the continued financial integrity of the
utilities, and give them an opportunity to be vital
market participants in the restructured market
following the transition, we will allow them to recover
[transition costs] (Preferred Policy Decision, mimeo p.
111).
During 1996, the California Legislature addressed electric industry
restructuring in the state. That effort culminated in AB 1890, signed into law
by Governor Wilson on September 23, 1996. AB 1890 broadly addresses all aspects
of electric industry restructuring, relying on the extensive foundation laid by
the Commission's Preferred Policy Decision.
- ------------
/2/ Transition costs are generally costs and obligations for
generation-related assets that may become uneconomic as a result of a
competitive generation market (Public Utilities Code ss. 367).
-2-
<PAGE>
AB 1890 establishes a transition period for the recovery of transition
costs (Public Utilities Code ss. 367(a)), and freezes utility rates during this
period (Public Utilities Code ss. 368(a)). Subject to certain exceptions,
utilities cannot include transition costs in their rates after the rate freeze
period. The rate freeze period is to end no later than March 31, 2002, and will
end earlier for a utility if it recovers all of its transition costs (excluding
excepted transition costs) before that date (Public Utilities Code ss.ss. 367(a)
and 368(a)).
As part of the Legislature's stated goal to ensure that California's
citizens achieve the benefits of electric industry restructuring at the earliest
possible date (AB 1890 (1996 Cal. Stat. ch. 854) ss. 1(a)), AB 1890 provides
that residential and small commercial customers shall receive a 10 percent rate
reduction, which will remain in effect throughout the rate freeze period (Public
Utilities Code ss. 368(a)). The financing of the rate reduction is to be through
the issuance of Rate Reduction Bonds. The Legislation described the process as
follows:
It is the intent of the Legislature that electrical
corporations shall, by June 1, 1997, or on the earliest
possible date, apply concurrently for financing orders from
the Public Utilities Commission and rate reduction bonds from
the California Infrastructure and Economic Development Bank
in amounts sufficient to achieve a rate reduction in the most
expeditious manner for residential and small commercial
customers of not less than 10 percent for 1998 and continuing
through March 31, 2002 (AB 1890 (1996 Cal. Stat. ch. 854) ss.
1(e)).
As provided by the Legislature, implementation of the rate reduction is
contingent upon timely and sufficient issuance of Rate Reduction Bonds.
Since the enactment of AB 1890, PG&E has been working with the other
California electric utilities; the staffs of the Commission, the California
Infrastructure and Economic Development Bank (Infrastructure Bank), and the
State Treasurer; and experts in the financial community including investment
bankers and rating agencies in order to develop a process that will provide for
timely approvals by the Commission and the Infrastructure Bank and a financing
structure that will maximize customer benefits associated with the issuance of
Rate Reduction Bonds.
-3-
<PAGE>
B. THE TIMING AND SIZE OF THE RATE REDUCTION BOND ISSUANCE
In anticipation of the rate reduction on January 1, 1998, issuance of the
Rate Reduction Bonds is expected to begin in the fourth quarter of 1997. PG&E
currently estimates the principal issuance amount to be approximately $3.1
billion. However, the actual issuance amount will depend on a number of
variables that are currently unknown; these variables include the interest rate
of the Bonds and the expected principal repayment terms. The issuance amount
will be determined based on market conditions when the Bonds are priced. In
addition, as is discussed in the Supporting Testimony, if electricity sales to
residential and small commercial customers are higher than is now forecast,
additional Bonds may need to be issued in the future.
Given the uncertainty surrounding the market conditions at the time of
issuance and future electricity sales during the rate freeze period, PG&E is
seeking authority in this application to issue up to $3.5 billion of Rate
Reduction Bonds. This will ensure that the principal amount is adequate to
support the 10 percent rate reduction, even though PG&E currently expects the
issuance amount to be less than $3.5 billion. As is described in the Supporting
Testimony, PG&E has proposed ratemaking mechanisms to ensure that residential
and small commercial customers receive all net benefits resulting from any Rate
Reduction Bond issuance. Therefore, should the issuance amount later prove to be
larger than was needed to support the 10 percent rate reduction, any additional
net benefits will be credited to these customers.
C. PROPOSED STRUCTURE OF THE RATE REDUCTION BOND TRANSACTION
The Rate Reduction Bonds will be asset backed securities issues by a
separate entity, which is expected to be the Infrastructure Bank, or an
affiliate of or entity approved by the Infrastructure Bank. The distinguishing
features of asset backed securities are that they are secured by a revenue
stream associated with a specific, identifiable asset, and that this asset is
separately owned and therefore separate from the credit risk of the originating
company. These features support a higher credit rating for these securities than
for those of the originating company.
The objective in structuring the transaction is to enable the Rate
Reduction Bonds to obtain the highest possible credit rating. Two elements are
critical in meeting this objective.
-4-
<PAGE>
First, the asset used to support the Rate Reduction Bonds must be created. AB
1890 authorizes the establishment of Transition Property, which is the right to
receive revenues from a non-bypassable tariff, called the Fixed Transition
Amounts (FTA) charges. AB 1890 provides that the FTA charges will be adjusted at
least annually via a Commission approved true-up mechanism, so that they are set
at a level which ensures timely recovery of the Rate Reduction Bond principal,
interest and related costs (Public Utilities Code ss.ss. 841(c), 841(e)).
Second, the Transition Property must be transferred to an entity which is
bankruptcy-remote from PG&E. This ensures that, in the event of a PG&E
bankruptcy, the FTA charges would not be included in PG&E's bankruptcy estate,
but rather would continue to be available to pay the debt service on the Rate
Reduction Bonds. In other words, the transfer of the Transition Property must be
a "true sale" for bankruptcy purposes.
Accordingly, PG&E proposes the following structure for the issuance of
RRBs:
1. PG&E will form a Special Purpose Entity (SPE), wholly owned and
organized by PG&E, which is bankruptcy-remote from PG&E. PG&E
will contribute a small amount of equity to the SPE and will, in
the form of a sale, transfer title to the Transition Property to
the SPE.
2. In order to acquire the Transition Property, the SPE will issue
debt securities (SPE Debt Securities) to an Issuer which will
issue the Rate Reduction Bonds. As provided for in AB 1890
(Public Utilities Code ss. 840(b)), the Issuer is expected to be
the Infrastructure Bank, or to be an affiliate of or entity
approved by the Infrastructure Bank. The Transition Property and
SPE equity will be used as collateral to secure the SPE Debt
Securities.
3. The Issuer will in turn issue Rate Reduction Bonds. The Rate
Reduction Bonds will either be secured by or will represent
beneficial interests in the debt of the SPE, which will mirror
the terms and conditions of the Rate Reduction Bonds. The
proceeds from the issuance of the Rate Reduction Bonds will be
transferred to the SPE. The SPE will then pay the proceeds to
PG&E in exchange for the Transition Property.
-5-
<PAGE>
The following schematic illustrates the proposed transaction, the structure of
which may be modified by the Infrastructure Bank:
The omitted graphic reflects the flow of the Transition Property and the
Equity Contribution from PG&E to the SPE, the flow of the Debt Securities from
the SPE to the Issuer, and the flow of the Rate Reduction Bonds from the Issuer
to the Investors; in the other direction, it reflects the flow of the Proceeds
from the Investors to the Issuer, the flow of the Proceeds from the Issuer to
the SPE, and the flow of the Proceeds from the SPE to PG&E.
D. FACTORS TO BE ADDRESSED TO ENHANCE THE RATE REDUCTION BONDS' CREDIT RATING,
THEREBY MAXIMIZING RATEPAYER BENEFITS
In evaluating the credit quality of the Rate Reduction Bonds, the rating
agencies will look to be sure that the transaction isolates the Transition
Property from PG&E's credit risk. In order to conclude that the Transition
Property is sufficiently isolated, the rating agencies will rely on a bankruptcy
opinion of counsel stating that the transfer of the Transition Property from
PG&E to the SPE is a "true sale" for bankruptcy purposes.
Next, rating agencies will focus on the credit risk associated with the
Transition Property itself. Considerations relating to that risk will include
the FTA True-up Mechanism; overcollateralization and other credit enhancements;
the risks associated with currently unknown third-party servicers that may
collect a portion of the FTA charges; and the legislative and regulatory risks
associated with the transaction.
The Commission can help to ensure that the highest possible credit ratings
can be obtained for the Rate Reduction Bonds, which will result in the greatest
ratepayer savings, by addressing the following factors in its Financing Order.
1. BANKRUPTCY CONSIDERATIONS
PG&E must provide to the rating agencies a satisfactory opinion of counsel,
at the time the Rate Reduction Bonds are issued, establishing that the transfer
of the Transition Property from PG&E to the SPE constitutes a "true sale" for
bankruptcy purposes. Accordingly, PG&E requests that the Commission approve the
proposed transaction structure, including the transfer of the Transition
Property to the bankruptcy-remote SPE.
-6-
<PAGE>
2. THE FTA TRUE-UP MECHANISM
In addition to the debt service on the Rate Reduction Bonds, the FTA
charges will include servicing fees and other ongoing costs associated with the
Rate Reduction Bond transaction. AB 1890 requires the Commission to approve an
FTA charges True-up Mechanism which will allow for adjustment of the FTA charges
at least annually (Public Utilities Code ss. 841(e)). This True-up Mechanism
will allow the FTA charges to be periodically adjusted to ensure that the Rate
Reduction Bonds are repaid in a timely manner, regardless of any variations that
would otherwise affect the FTA charges and cause the actual amortization of the
Rate Reduction Bonds to diverge from the scheduled amortization. The design and
implementation of the FTA True-up Mechanism are critical to the rating agencies
in their determination of the reliability and adequacy of debt service payments.
The allowed frequency of FTA charges adjustments, as well as the timely
Commission review and approval of true-up filings, will be important factors in
the rating agencies' evaluation of the credit quality of the Rate Reduction
Bonds. PG&E requests that the Commission approve the FTA True-up Mechanisms
described in the Supporting Testimony.
3. OVERCOLLATERALIZATION AND OTHER FORMS OF CREDIT ENHANCEMENT
Additional credit enhancement for the Rate Reduction Bonds in the form of
overcollateralization is expected to be required by the rating agencies. To
overcollateralize the Rate Reduction Bonds means to secure them with Transition
Property in an amount larger than the total principal amount of the Bonds.
Overcollateralization thus provides further assurance that bondholders will
receive all principal and interest due them. The rating agencies and the
Infrastructure Bank will determine the amount of needed overcollateralization.
PG&E requests that the Commission authorize the FTA charges to include
overcollateralization amounts as the Infrastructure Bank determines to be
necessary. As is described in the Supporting Testimony, ratepayers will receive
a credit in future rates for any overcollateralization amounts not needed to
retire Rate Reduction Bonds.
Other forms of credit enhancement customary for securitization transactions
may also be used, if determined to be cost-effective. They would be implemented
at the time the Bonds are issued.
-7-
<PAGE>
4. RATE REDUCTION BOND SERVICING
In developing their ratings, rating agencies are also very concerned about
the financial strength and the billing and collecting experience of the Rate
Reduction Bond servicer(s) (the entity or entities responsible for billing and
collecting the FTA charges). While PG&E will be the initial servicer, it is
possible that pursuant to the Commission's cost separation proceeding in
electric industry restructuring, in the future currently unknown third parties
will be billing and collecting the FTA charges from some customers. Unless these
third party servicers are required to meet minimum billing and collection
experience standards, and creditworthiness criteria, the rating agencies will
either impose additional credit enhancement requirements or assign lower credit
ratings on the Bonds.
PG&E is therefore requesting that the Commission not approve a third party
servicer without making a determination that the approval will not cause the
then-current rating of the Rate Reduction Bonds to be withdrawn or downgraded.
This will provide assurance to the credit rating agencies that the Bonds' rating
will not be undermined in the future because of a third party servicer.
Additionally, PG&E is requesting several more specific findings to address the
potential concerns of rating agencies with respect to the reliability of
collection of the FTA charges if they are collected by third parties.
5. LEGISLATIVE AND REGULATORY RISK
Additional factors the rating agencies will consider when rating the Rate
Reduction Bonds include the legislative risks associated with AB 1890, including
the risk that AB 1890 could be modified in the future. Since AB 1890 was
unanimously passed by the California Legislature, and it results in economic
benefits to residential and small commercial ratepayers, PG&E expects the rating
agencies to conclude that the legislative risk associated with the transaction
will not affect the Bonds' rating.
The rating agencies will also analyze the regulatory risk associated with
the transaction. In accordance with AB 1890, the Financing Order and the FTA
charges will be irrevocable, and the Commission will not have authority either
by rescinding, altering or amending any Financing Order, to revalue the costs of
providing, recovering, financing, or refinancing the transition costs
-8-
<PAGE>
(Public Utilities Code ss. 841(c)). The Financing Order, particularly with
regard to the establishment of the FTA charges, the FTA True-up Mechanism, the
Transition Property and the third party servicing standards, will be carefully
reviewed by the rating agencies. PG&E has requested several specific findings,
set out at the conclusion of this application, to address these issues and
provide assurance to the rating agencies so that the Bonds may receive the
highest possible rating.
E. REVENUE REQUIREMENT AND RATEMAKING MECHANISMS
In this application, PG&E is also proposing revenue requirement and
ratemaking mechanisms which will
1. incorporate the Rate Reduction Bond transaction into the
Competition Transition Charge (CTC) ratemaking mechanisms
described in PG&E's CTC application, A. 96-08-070;
2. ensure that residential and small commercial customers receive
all net benefits associated with the amount of the Rate Reduction
Bonds issued; and
3. maintain the non-bypassability of the FTA charges as is required
by AB 1890. (For this purpose PG&E proposes mechanisms similar to
those proposed in A. 96-08-070 to be used to enforce the
non-bypassability of the CTC.)
III. RATE PROPOSAL
Under PG&E's proposal, residential and small commercial electric bills will
decrease by 10 percent on January 1, 1998, conditioned upon timely and
sufficient issuance of Rate Reduction Bonds. This decrease will remain in place
throughout the rate freeze period. For purposes of this application, small
commercial customers are as defined in AB 1890, and are those commercial
customers with maximum peak demands of less than 20 kW. There will be some
commercial customers in PG&E's Small Light and Power, Medium Light and Power and
E-19 classes who will be eligible for this bill reduction.
-9-
<PAGE>
These customers' tariff rates will not change, but they will receive a 10
percent bill credit on their bills. Affected customers who elect direct access
will receive a 10 percent bill credit based on what their full service bills
would have been.
IV. RECOMMENDED SCHEDULE
PG&E is requesting that the Commission expeditiously adopt this application
within 120 days of its date of filing, as provided for in AB 1890 (Public
Utilities Code ss. 841(e)), and consistent with Resolution ALJ-173, issued on
April 23, 1997. Time is of the essence in order to allow the Rate Reduction
Bonds to be issued in the fourth quarter of 1997, as is necessary to support the
10 percent rate reduction for residential and small commercial customers to be
implemented on January 1, 1998. Further, issuance of the Bonds is required by AB
1890, once the Commission finds that their issuance will lower rates for
residential and small commercial customers.
Below is a recommended schedule for the processing of this application,
based on Resolution ALJ-173.
PROPOSED SCHEDULE FOR RATE REDUCTION BOND
APPLICATION AND 10 PERCENT RATE REDUCTION
- ---------------------------------------- ------------------------------------
EVENT DATE
- ---------------------------------------- ------------------------------------
Utilities File Application May 6, 1997
- ---------------------------------------- ------------------------------------
Notice To Customers of Rate Reduction May 16 - June 16, 1997
- ---------------------------------------- ------------------------------------
Response or Protest To Applications May 20, 1997
- ---------------------------------------- ------------------------------------
Utilities' Replies To May 27, 1997
Responses/Protests
- ---------------------------------------- ------------------------------------
Prehearing Conference May 27, 1997
- ---------------------------------------- ------------------------------------
Hearings, if needed May 28 -June 3, 1997
- ---------------------------------------- ------------------------------------
Opening Briefs June 13, 1997
- ---------------------------------------- ------------------------------------
Reply Briefs June 25, 1997
- ---------------------------------------- ------------------------------------
Draft or ALJ Proposed Decision August 4, 1997
- ---------------------------------------- ------------------------------------
Comments on PD August 25, 1997
- ---------------------------------------- ------------------------------------
Reply Comments on PD September 2, 1997
- ---------------------------------------- ------------------------------------
Commission Financing Orders September 3, 1997
- ---------------------------------------- ------------------------------------
Rate Reduction Bonds Issued/FTA Charge October 1997 - December 1997
Implemented
- ---------------------------------------- ------------------------------------
Ten Percent Reduction January 1, 1998
- ---------------------------------------- ------------------------------------
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<PAGE>
V. GENERAL INFORMATION
A. STATUTORY AND REGULATORY AUTHORITY (RULE 15)
This application is made pursuant to ss.ss. 451, 454, 456, 701, and 840-846
of the Public Utilities Code of the State of California, Rules 2-8, 15-16, 23
and 24 of the Commission's Rules of Practice and Procedure, and Resolution
ALJ-173, issued on April 23, 1997. While this application requests a rate
decrease, PG&E is nonetheless providing the information listed in Rules 23 and
24, which are by their terms only applicable to rate increases.
B. LEGAL NAME AND PRINCIPAL PLACE OF BUSINESS (RULE 15(a))
The legal name of the applicant is Pacific Gas and Electric Company. The
location of applicant's principal place of business is San Francisco,
California. Its mailing address is P.O. Box 7442, San Francisco, California
94120.
C. CORRESPONDENCE AND COMMUNICATION REGARDING THE APPLICATION (RULE 15(b))
PG&E's attorneys in this matter are Michelle L. Wilson and Mark R. Huffman.
All correspondence and communication regarding this application should be
addressed to:
Mark R. Huffman
Pacific Gas and Electric Company
Mail Code B30A
P.O. Box 7442
San Francisco, CA 94120-7442
Telephone: (415) 973-7497
Fax: (415) 973-0516
D. ARTICLES OF INCORPORATION (RULE 16(a))
PG&E is and ever since October 10, 1906, has been an operating public
utility corporation organized under California law. It is engaged principally in
the business of furnishing electric and gas services in California. A certified
article of PG&E's Restated Articles of Incorporation dated April 28, 1997, is
attached to this application as Exhibit A.
E. BALANCE SHEET AND INCOME STATEMENTS (RULE 23(a))
PG&E's balance sheet as of December 31, 1996, and income statement covering
the twelve month period ending December 31, 1996, are shown in Exhibit B.
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<PAGE>
F. PRESENT AND PROPOSED RATES (RULES 23(b) AND 23(c))
PG&E's rates and charges for electricity service are contained in PG&E's
electric tariffs on file with the Commission. They are summarized in Exhibit C.
PG&E's proposed residential and small commercial rates are also shown in Exhibit
C, and PG&E's rate proposal is summarized in Section III of this application.
G. PROPERTY AND EQUIPMENT (RULE 23(d))
A summary of PG&E's Electric Department property and equipment, their
original costs and the depreciation reserve applicable to them, is shown in
Exhibit D. A more detailed description of PG&E's electric property and equipment
is included in PG&E's Exhibit in A 94-12-015 filed on December 9, 1994, and it
is incorporated herein by reference.
RATE OF RETURN SUMMARY (RULES 23(e) AND 23(f))
The revenues, expenses, and rate of return of PG&E's Electric
Department for the recorded year 1996, are shown on Exhibit E. Forecasted
results of operations under this application are set forth in Exhibit F.
I. SHOWING (RULE 23(g))
All of PG&E's exhibits in support of this application are included.
Exhibit A - PG&E's Restated Articles of Incorporation
Exhibit B - Balance Sheet and Income Statement
Exhibit C - Present and Proposed Electric Rates
Exhibit D - Summary of Electric Department Property
Exhibit E - Recorded Revenues, Expenses and Rate of Return
Exhibit F - Forecasted Results of Operation
Exhibit G - Tax Method of Depreciation
Exhibit H - Affected Governmental Entities
Separately Bound - Supporting Testimony
PG&E is ready at this time to proceed with its showing.
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<PAGE>
J. DEPRECIATION DEDUCTION FOR FEDERAL INCOME TAX (RULE 23(h))
A statement of PG&E's method of computing the depreciation deduction for
federal income tax purposes is shown in Exhibit G.
K. PROXY STATEMENT (RULE 23(i))
A copy of PG&E's most recent proxy statement to its shareholders dated
March 3, 1997, was provided to the Commission on April 1, 1997, in Application
97-04-001, and is incorporated herein by reference.
L. SERVICE OF APPLICATION (RULE 24)
Consistent with Rule 24 of the Commission's Rules of Practice and
Procedure, PG&E will notify the affected governmental entities listed in Exhibit
H of this application. As directed by Resolution ALJ-173, PG&E will also serve a
copy of this application on all parties requesting it. In addition, PG&E will
serve a notice of availability of the application on all parties in the
consolidated CTC proceeding (A. 96-08-001, et al), and all parties in the
Commission's Electric Industry Restructuring Proceeding (OIR/OII
94-04-031/94-04-032).
M. FORM OF FINANCING ORDER (RULE 2, FINANCING ORDER RULES)
The recommended findings, approvals and authorizations set out in Section
VI of this application, Conclusion, represent the form of Financing Order PG&E
is requesting.
VI. CONCLUSION
AB 1890 is comprised of a complex set of interdependent provisions that
together authorize, permit and in some instances mandate certain actions by
PG&E, the Commission and the Infrastructure Bank, among others, in order to
implement and maintain the Legislature's intended balance among industry
deregulation, rate reduction and transition cost recovery. In order that the
Fixed Transition Amounts, FTA charges and related Transition Property be
established, the Rate Reduction Bonds be issued, and the residential and small
commercial rate reduction be implemented as intended, AB 1890 contemplates that
certain findings, approvals and authorizations be included in the Financing
Order. Transactional constraints, such as legal considerations and rating agency
concerns, give rise to the need for additional findings, approvals and
authorizations in the Financing Order.
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<PAGE>
Therefore, in addition to the duties, obligations, rights and remedies
provided for by AB 1890 and other applicable laws, and in addition to seeking
general authority to enter into and perform the transactions described in this
application, Pacific Gas and Electric Company respectfully requests that the
Commission in the Financing Order specifically make the following findings,
approvals and authorizations:
A. GENERAL AUTHORIZATION
1. Find that PG&E may recover a portion of its transition costs and the costs
of providing, recovering, financing and refinancing transition costs in an
aggregate principal amount of up to $3.5 billion from proceeds of SPE Debt
Securities and Rate Reduction Bonds, which shall include all costs of
issuance approved by the Infrastructure Bank, and that the owner of the
Transition Property may recover principal, interest and related costs
associated with the SPE Debt Securities and the Rate Reduction Bonds
through Fixed Transition Amounts, as described in this application;
2. Find, as required by AB 1890, that the designation of the Fixed Transition
Amounts and the issuance of up to $3.5 billion of SPE Debt Securities and
Rate Reduction Bonds in connection with such Fixed Transition Amounts will
reduce rates that residential and small commercial customers of PG&E would
have paid if the Financing Order were not adopted;
3. Find that the amount of SPE Debt Securities and Rate Reduction Bonds shall
be as determined using the sizing methodology described in this application
based on market conditions at the time the Rate Reduction Bonds are priced,
that the principal on the SPE Debt Securities and the Rate Reduction Bonds
shall be repaid in substantially equal annual amounts, that the final
expected maturity of the SPE Debt Securities and the Rate Reduction Bonds
shall be no later than ten years from the date of issuance, with a final
legal maturity to be determined by the Infrastructure Bank, and that the
Infrastructure Bank shall have the authority to determine the
overcollateralization amount required;
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<PAGE>
B. THE FIXED TRANSITION AMOUNTS AND FTA CHARGES
4. Determine that the methodology to calculate the FTA charges associated with
Rate Reduction Bond issuance shall be as described in this application, and
that these FTA charges shall be filed with the Commission in Advice Letters
(the "Issuance Advice Letters"); and find that the FTA charges may be
included as a separate line item on customers' bills;
5. Find that each Issuance Advice Letter associated with the Financing Order
shall be effective five business days after filing, upon which it shall be
deemed a part of this Financing Order for purposes of AB 1890, and that the
FTA charges established thereby constitute Fixed Transition Amounts;
6. Require that, to the extent feasible, if residential and small commercial
customers fail to pay their utility bills in full, any shortfall in
revenues received shall be allocated between the FTA charges and all other
components of the customers' bills based on the ratio of the amount of the
bills relating to the FTA charges and the amount relating to all other
components of the bills;
C. THE FTA CHARGES TRUE-UP MECHANISM
7. Establish that the procedures for the expeditious approval by the
Commission of periodic adjustments (the "True-up Mechanisms") to the FTA
charges (as may be necessary to ensure timely recovery of all transition
costs that are the subject of the Financing Order, and the costs of capital
associated with the provision, recovery, financing, or refinancing thereof,
including the costs of issuing, servicing and retiring the SPE Debt
Securities and Rate Reduction Bonds contemplated by the Financing Order)
shall be as described in this application, and find that such True-up
Mechanisms shall continue until the SPE Debt Securities and the Rate
Reduction Bonds are paid in full;
8. Determine that the methodology to calculate routine FTA charge adjustments
shall be as described in this application, and that such adjustments shall
be filed with the Commission in routine True-up Mechanism Advice Letters;
determine that such routine True-up Mechanism Advice Letters shall be filed
with the Commission annually at least 15 days
-15-
<PAGE>
before the end of each
calendar year and the resulting adjustments to the FTA charges shall be
implemented at the beginning of the next calendar year; and determine that
additionally such routine True-up Mechanism Advice Letters may be filed at
least 15 days before the end of any calendar quarter and the resulting
adjustments to the FTA charges shall be implemented at the beginning of the
next calendar quarter;
9. Find that a non-routine True-up Mechanism Advice Letter may be filed at
least 90 days before the end of any calendar quarter and the resulting
adjustments to the FTA charges shall be implemented at the beginning of the
next calendar quarter;
10. Find that a True-up Mechanism Advice Letter shall be filed at least 15 days
before each anniversary of the issuance of the Financing Order, and that
the Commission shall determine, on the Finance Order issuance anniversary,
as required by AB 1890, whether adjustments to the FTA charges are
required, with the resulting adjustments to the FTA charges, if necessary,
to be implemented within 90 days of the Finance Order issuance anniversary;
D. TRANSITION PROPERTY
11. Find that upon the effective date of each Issuance Advice Letter associated
with the Financing Order, all of the Transition Property identified in such
Advice Letter constitutes a current property right and shall thereafter
continuously exist as property for all purposes;
12. Find that the Transition Property identified in an Issuance Advice Letter
associated with the Financing Order shall include, without limitation (1)
the right, title and interest in and to the FTA charges set forth in such
Advice Letter, as adjusted from time to time, (2) the right to be paid the
total amounts set forth in such Advice Letter, (3) the right, title and
interest in and to all revenues, collections, claims, payments, money, or
proceeds of or arising from such FTA charges, and (4) all rights to obtain
adjustments to such FTA charges under the True-up Mechanism;
13. Find that the holders of the Transition Property are entitled to recover
Fixed Transition Amounts in the aggregate amount equal to the principal
amount of the SPE Debt Securities and the Rate Reduction Bonds, all
interest thereon, the overcollateralization
-16-
<PAGE>
amount and all related fees, costs and expenses in regard of the SPE Debt
Securities and Rate Reduction Bonds until they have been paid in full;
E. STEPS IN THE RATE REDUCTION BOND TRANSACTION
1. TRANSFER OF TRANSITION PROPERTY TO THE SPE
14. Approve the sale by PG&E of the Transition Property identified in an
Issuance Advice Letter to one or more SPEs, as identified in such Advice
Letter;
15. Find that, upon the sale by PG&E of the Transition Property to one or more
SPEs, (1) such SPE(s) shall have all of the rights originally held by PG&E
with respect to such Transition Property, including, without limitation,
the right to exercise any and all rights and remedies to collect any
amounts payable by any customer in respect of such Transition Property,
notwithstanding any objection or direction to the contrary by PG&E, and (2)
any payment by any customer to such SPE shall discharge such customer's
obligations in respect of such Transition Property to the extent of such
payment, notwithstanding any objection or direction to the contrary by
PG&E;
16. Find that, upon the sale by PG&E of the Transition Property to one or more
SPEs, PG&E shall not be entitled to recover the FTA charges associated with
such Transition Property other than for the benefit of the holders of the
SPE Debt Securities and the Rate Reduction Bonds in accordance with PG&E's
duties as servicer;
17. Find that the SPE(s) identified in an Issuance Advice Letter, if so
approved by the Infrastructure Bank, constitute Financing Entities;
2. TRANSFER OF SPE DEBT SECURITIES TO THE ISSUER
18. Approve the issuance by the SPE(s), identified in an Issuance Advice Letter
and approved by the Infrastructure Bank, of SPE Debt Securities to one or
more Issuers, as identified in such Advice Letter, on terms to be approved
by the Infrastructure Bank; provided, however, that the aggregate amount of
SPE Debt Securities related to all such PG&E Advice Letters associated with
the Financing Order shall not exceed $3.5 billion;
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<PAGE>
19. Approve the pledging by the SPE(s), identified in an Issuance Advice
Letter, as security for the SPE Debt Securities, of such SPE's right, title
and interest in and to the Transition Property, and of such SPE's other
assets;
3. ISSUANCE OF THE RATE REDUCTION BONDS
20. Approve, the issuance by the Issuer(s), to the extent stated in an Issuance
Advice Letter and approved by the Infrastructure Bank, of Rate Reduction
Bonds, on terms to be approved by the Infrastructure Bank; provided,
however, that the aggregate amount of Rate Reduction Bonds related to all
such PG&E Advice Letters associated with the Financing Order shall not
exceed $3.5 billion;
21. Approve, to the extent stated in an Issuance Advice Letter, the pledging by
the Issuer(s), as security for the Rate Reduction Bonds, of such Issuer's
right, title and interest in and to the SPE Debt Securities and all
security therefor;
22. Find that any default under the documents relating to the SPE Debt
Securities or the Rate Reduction Bonds shall entitle the holders of the SPE
Debt Securities or the Rate Reduction Bonds or the trustees or
representatives for such holders to exercise any and all rights or remedies
such holders or such trustees or representatives therefor may have pursuant
to any statutory lien on the Transition Property;
F. RATE REDUCTION BOND SERVICING
23. Authorize PG&E to contract with one or more SPEs and/or Issuers to collect
amounts in respect of the FTA charges for the benefit and account of such
SPEs and/or Issuers, and to account for and remit these amounts to or for
the account of such SPEs and/or Issuers;
24. Provide that, in the event of default by PG&E in payment to or for the
benefit of the SPE of the FTA charges, the Commission, upon the application
by (1) the holders of the SPE Debt Securities or the Rate Reduction Bonds
and the trustees or representatives therefor as beneficiaries of any
statutory lien permitted by the Public Utilities Code, (2) the SPE or its
assignees, (3) the Issuer, or (4) pledgees or transferees, including
transferees under Public Utilities Code Section 844, of the Transition
Property, shall order the sequestration
-18-
<PAGE>
and payment to or for the benefit of the SPE or such other party of
revenues arising with respect to the Transition Property;
25. Find that the Commission shall not approve or require any third party
servicer(s) to replace PG&E in any of its servicing functions in whole or
in part without first determining that approving or requiring such third
party servicer(s) to replace PG&E will not cause the then-current rating of
the Rate Reduction Bonds to be withdrawn or downgraded;
26. Find that regardless of who is responsible for billing, residential and
small commercial customers shall continue to be responsible for FTA
charges;
27. Find that if a third party meters and bills for the FTA charges, PG&E must
have access to information on kilowatt-hour billing and usage by customers
to provide for proper reporting to the SPE and to perform its obligations
as servicer;
28. Find that in the case of a third party default, billing responsibilities
must be promptly transferred to another party to minimize losses;
29. Find that the failure of customers to pay FTA charges shall allow shut-off
by PG&E on behalf of the SPE of the customers failing to pay FTA charges,
in accordance with Commission-approved shut-off policies;
G. RATE REDUCTION AUTHORIZATION
30. Conditioned on the timely and sufficient issuance of Rate Reduction Bonds,
authorize, as required by AB 1890, PG&E to provide the 10 percent rate
reduction via a bill credit to eligible customers effective January 1,
1998;
31. Find that for purposes of eligibility to receive the rate reduction and
responsibility to pay for FTA charges, PG&E's residential and small
commercial customers shall be as described in this application;
H. RATEMAKING MECHANISM AUTHORIZATIONS
32. Authorize PG&E to establish by Advice Letter filing(s), the Rate Reduction
Bond Memorandum Account, FTA charges tariff language, and modifications to
PG&E's Preliminary Statement and CTC Ratemaking Mechanism as described in
this application;
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<PAGE>
33. Adopt the provisions described in this application to ensure that the FTA
charges are non-bypassable, and authorize the rate collection methods
relating thereto;
I. ADDITIONAL AUTHORIZATIONS AND APPROVALS
34. Provide that this Financing Order shall become effective in accordance with
its terms only when PG&E files with the Commission its written consent to
all terms and conditions of the Order; and
35. Provide such additional authorizations and approvals as may be necessary
for PG&E to carry out the transactions described in this application.
Dated at San Francisco, California, this 6th day of May, 1997.
Respectfully submitted,
-------------------------
KENT M. HARVEY
Vice President and Treasurer
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<PAGE>
MICHELLE L. WILSON
MARK R. HUFFMAN
By
--------------------
MARK R. HUFFMAN
Law Department
Pacific Gas and Electric Company
Post Office Box 7442
San Francisco, CA 94120
Telephone: (415) 973-7497
Fax: (415) 973-0516
Attorneys for
PACIFIC GAS AND ELECTRIC COMPANY
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<PAGE>
VERIFICATION
I, the undersigned say, I am an officer of Pacific Gas and Electric
Company, a corporation, and am authorized to make his Verification for and on
behalf of the said corporation and I make this Verification for that reason. I
have read the foregoing pleading and I am informed and believe that the matters
therein are true and on that ground I allege that the matters stated therein are
true.
I declare under penalty of perjury that the foregoing is true and correct.
Executed on May 6, 1997, at San Francisco, California.
---------------------------
KENT M. HARVEY
Vice President and Treasurer
<PAGE>
EXHIBIT A
PG&E'S RESTATED ARTICLES OF INCORPORATION
23
<PAGE>
EXHIBIT A
[State of CA Logo]
SECRETARY OF STATE
I, BILL JONES, Secretary of State of the State of California, hereby
certify:
That the annexed transcript has been compared with the corporate record on
file in this office, of which it purports to be a copy, and that same is full,
true and correct.
IN WITNESS WHEREOF; I execute this
certificate and affix the Great Seal of
the State of California this
APR 29 1997
/s/ Bill Jones
Secretary of State
[CA State Seal]
A-1
<PAGE>
RESTATED ARTICLES OF INCORPORATION OF
PACIFIC GAS AND ELECTRIC COMPANY
STANLEY T. SKINNER and LESLIE H. EVERETT certify that:
1. They are the Chairman of the Board and Chief Executive Officer, and
the Vice President and Corporate Secretary, respectively, of Pacific
Gas and Electric Company, a California corporation (the "Company").
2. The Articles of Incorporation of the corporation, as amended to the
date of the filing of this certificate, including the amendments set
forth herein but not separately filed (and with the omissions required
by Section 910 of the Corporations Code) are amended and restated as
follows:
FIRST: That the name of said corporation shall be
PACIFIC GAS AND ELECTRIC COMPANY.
SECOND: The purpose of the corporation is to engage in any lawful act
or activity for which a corporation may be organized under the General
Corporation Law of California other than the banking business, the trust company
business or the practice of a profession permitted to be incorporated by the
California Corporations Code.
The right is reserved to this corporation to amend the whole or any
part of these Articles of Incorporation in any respect not prohibited by law.
THIRD: That this corporation shall have perpetual existence.
FOURTH: The corporation elects to be governed by all of the
provisions of the General Corporation Law (as added to the California
Corporations Code effective January 1, 1977, and as subsequently amended) not
otherwise
A-2
<PAGE>
applicable to this corporation under Chapter 23 of said General Corporation Law.
FIFTH: That the Board of Directors of this corporation shall consist
of such number of directors, not less than fourteen (14) nor more than seventeen
(17), as shall be prescribed in the Bylaws.
The Board of Directors by a vote of two-thirds of the whole Board may
appoint from the Directors an Executive Committee, which Committee may exercise
such powers as may lawfully be conferred upon it by the Bylaws of the
Corporation. Such Committee may prescribe rules for its own government and its
meetings may be held at such places within or without California as said
Committee may determine or authorize.
SIXTH: The liability of the directors of the corporation for monetary
damages shall be eliminated to the fullest extent permissible under California
law.
SEVENTH: The corporation is authorized to provide indemnification of
agents (as defined in Section 317 of the California Corporations Code) through
bylaws, resolutions, agreements with agents, vote of shareholders or
disinterested directors, or otherwise, in excess of the indemnification
otherwise permitted by Section 317 of the California Corporations Code, subject
only to the applicable limits set forth in Section 204 of the California
Corporations Code.
EIGHTH: The total number of shares which this corporation is
authorized to issue is eight hundred eighty-five million (685,000,000) of the
aggregate par value of six billion eight hundred seventy-five million dollars
($6,875,000,000). All of these shares shall have full voting rights.
Said eight hundred eighty-five million (885,000,000) shares shall be
divided into three classes, designated as common stock, first preferred stock
and $100 first preferred stock. Eight hundred million (800,000,000) of said
shares shall be common stock, of the par value of $5 per share, seventy-five
million (75,000,000) of said shares shall be first preferred stock, of the par
value of $25 per share, and ten million
A-3
<PAGE>
(10,000,000) of said shares shall be $100 first preferred stock, of the par
value of $100 per share.
FIRST PREFERRED STOCK
AND $100 FIRST PREFERRED STOCK
The first preferred stock and $100 first preferred stock each shall be
divided into series. The first series of first preferred stock shall consist of
four million two hundred eleven thousand six hundred sixty-two (4,211,662)
shares and be designated as Six Per Cent First Preferred Stock. The second
series of first preferred stock shall consist of one million one hundred
seventy-three thousand one hundred sixty-three (1,173,163) shares and be
designated as Five and One-Half Per Cent First Preferred Stock. The third
series of first preferred stock shall consist of four hundred thousand (400,000)
shares and be designated as Five Per Cent First Preferred Stock. The remainder
of said first preferred stock, viz., 69,215,175 shares, and all of the $100
first preferred stock may be issued in one or more additional series, as
determined from time to time by the Board of Directors. Except as provided
herein, the Board of Directors is hereby authorized to determine and alter the
rights, preferences, privileges and restrictions granted to or imposed upon the
first preferred stock or $100 first preferred stock or any series thereof with
respect to any wholly unissued series of first preferred stock or $100 first
preferred stock, and to fix the number of shares of any series of first
preferred stock or $100 first preferred stock and the designation of any such
series of first preferred stock or $100 first preferred stock. The Board of
Directors, within the limits and restrictions stated in any resolution or
resolutions of the Board of Directors originally fixing the number of shares
constituting any series, may increase or decrease (but not below the number of
shares of such series then outstanding) the number of shares of any series
subsequent to the issue of shares of that series.
The owners and holders of shares of said first preferred stock and
$100 first preferred stock, when issued as fully paid, are and shall be entitled
to receive, from the date of issue of such shares, out of funds legally
available therefor, cumulative preferential dividends, I when and as declared by
the Board of Directors, at the following rates upon the par value of
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<PAGE>
their respective shares, and not more, viz.: Six per cent (6%) per year upon Six
Per Cent First Preferred Stock; five and one-half per cent (5-l~2%) per year
upon Five and One-Half Per Cent First Preferred Stock; five per cent (5%) per
year upon Five Per Cent First Preferred Stock; and upon the shares of each
additional series of said first preferred stock and of each series of $100 first
preferred stock the dividend rate fixed therefor; and such dividends on both
classes of first preferred stock and $100 first preferred stock shall be
declared and shall be either paid or set apart for payment before any dividend
upon the shares of common stock shall be either declared or paid.
Upon the liquidation or dissolution of this corporation at any time
and in any manner, the owners and holders of shares of said first preferred
stock and $100 first preferred stock issued as fully paid will be entitled to
receive an amount equal to the par value of such shares plus an amount equal to
all accumulated and unpaid dividends thereon to and including the date fixed for
such distribution or payment before any amount shall be paid to the holders of
said common stock.
If any share or shares of first preferred stock and $100 first
preferred stock shall at any time be issued as only partly paid, the owners and
holders of such partly paid share or shares shall have the right to receive
dividends and to share in the assets of this corporation upon its liquidation or
dissolution in all respects like the owners and holders of fully paid shares of
first preferred stock and $100 first preferred stock, except that such right
shall be only in proportion to the amount paid on account of the subscription
price for which such partly paid share or shares shall have been issued.
The unissued shares of said first preferred stock and $100 first
preferred stock may be offered for. subscription or sale or in exchange for
property and be issued from time to time upon such terms and conditions as said
Board of Directors shall prescribe. I
The first three series of said first preferred stock, namely, the Six
Per Cent First Preferred Stock, the Five and One-Half Per Cent First Preferred
Stock, and the Five Per Cent First Preferred Stock, are not subject to
redemption.
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<PAGE>
Any or all shares of each series of said first preferred stock and
$100 first preferred stock other than said first three series of first preferred
stock may be redeemed at the option of this corporation, at any time or from
time to time, at the redemption price fixed for such series together with
accumulated and unpaid dividends at the rate fixed therefor to and including the
date fixed for redemption. If less than all the outstanding shares of any such
series are to be redeemed, the shares to be redeemed shall be determined pro
rata or by lot in such manner as the Board of Directors may determine.
Unless the certificate of determination for any series of the first
preferred stock or the $100 first preferred stock shall otherwise provide,
notice of every such redemption shall be published in a newspaper of general
circulation in the City and County of San Francisco, State of California, and in
a newspaper of general circulation in the Borough of Manhattan, City and State
of New York, at least once in each of two (2) successive weeks, commencing not
earlier than sixty (60) nor later than thirty (30) days before the date fixed
for redemption; successive publications need not be made in the same newspaper.
A copy of such notice shall be mailed within the same period of time to each
holder of record, as of the record date, of the shares to be redeemed, but the
failure to mail such notice to any shareholder shall not invalidate the
redemption of such shares.
From and after the date fixed for redemption, unless default be made
by this corporation in paying the amount due upon redemption, dividends on the
shares called for redemption shall cease to accrue, and such shares shall be
deemed to be redeemed and shall be no longer outstanding, and the holders
thereof shall cease to be shareholders with respect to such shares and shall
have no rights with respect thereto except the right to receive from this
corporation upon surrender of their certificates the amount payable upon
redemption without interest. Or, if this corporation shall deposit, on or prior
to the date fixed for redemption, with any bank or trust company in the City and
County of San Francisco, having capital, surplus and undivided profits
aggregating at least five million dollars ($5,000,000), as a trust fund, a sum
sufficient to redeem the shares called for redemption, with irrevocable
instructions and authority to such
A-6
<PAGE>
bank or trust company to publish or complete the publication of the notice of
redemption (if this corporation shall not have theretofore completed publication
of such notice), and to pay, on and after the date fixed for redemption, or on
and after such earlier date as the Board of Directors may determine, the amount
payable upon redemption of such shares, then from and after the date of such
deposit (although prior to the date fixed for redemption) such shares shall be
deemed to be redeemed; and dividends on such shares shall cease to accrue after
the date fixed for redemption. The said deposit shall be deemed to constitute
full payment of the shares to their respective holders and from and after the
date of such deposit the shares shall be no longer outstanding, and the holders
thereof shall cease to be shareholders with respect to such shares and shall
have no rights with respect thereto except the right to receive from said bank
or trust company the amount payable upon redemption of such shares, without
interest, upon surrender of their certificates therefor, and except, also, any
right which such shareholders may then have to exchange or convert such shares
prior to the date fixed for redemption. Any part of the funds so deposited
which shall not be required for redemption payments because of such exchange or
conversion shall be repaid to this corporation forthwith. The balance, if any,
of the funds so deposited which shall be unclaimed at the end of six (6) years
from the date fixed for redemption shall be repaid to this corporation together
with any interest which shall have been allowed thereon; and thereafter the
unpaid holders of shares so called for redemption shall have no claim for
payment except as against this corporation.
All shares of the first preferred stock and $100 first preferred stock
shall rank equally with regard to preference in dividend and liquidation rights,
except that shares of different classes or different series thereof may differ
as to the amounts of dividends or liquidation payments to which they are
entitled, as herein set forth.
A-7
<PAGE>
COMMON STOCK
When all accrued dividends upon all of the issued and outstanding
shares of the first preferred stock and $100 first preferred stock of this
corporation shall have been declared and shall have been paid or set apart for
payment, but not before, dividends may be declared and paid, out of funds
legally available therefor, upon all of the issued and outstanding shares of
said common stock.
Upon the liquidation or dissolution of this corporation, after the
owners and holders of such first preferred stock and $100 first preferred stock
shall have been paid the full amount to which they shall have been entitled
under the provisions of these Articles of Incorporation, the owners and holders
of such common stock shall be entitled to receive and to have paid to them the
entire residue of the assets of this corporation in proportion to the number of
shares of said common stock held by them respectively.
If any share or shares 0(Pounds) common stock shall at any time be
issued as only partly paid, the owners and holders of such partly paid share or
shares shall have the right to receive dividends and to share in the assets of
this corporation upon its liquidation or dissolution in all respects like the
owners and holders of fully paid shares of common stock, except that such right
shall be only in proportion to the amount paid on account of the subscription
price for which such partly paid share or shares shall have been issued.
The unissued shares of said common stock may be offered for
subscription or sale or in exchange for property and be issued from time to time
upon such terms and conditions as said Board of Directors may prescribe.
PROHIBITION AGAINST ASSESSMENTS
Shares of such stock, whether first preferred, $100 first preferred
stock or common stock, the subscription price of which shall have been paid in
full, whether such price be par or more or less than par, shall be issued as
fully paid shares and shall never be subject to any call or assessment for any
purpose
A-8
<PAGE>
whatever. Shares of such stock, whether first preferred, $100 first preferred
stock or common stock, a part only of the subscription price of which shall have
been paid, shall be subject to calls for the unpaid balance of the subscription
price thereof. But no call made on partly paid first preferred stock, partly
paid $100 first preferred stock or partly paid common stock shall be recoverable
by action or be enforceable otherwise than by sale or forfeiture of delinquent
stock in accordance with the applicable provisions of the Corporations Code of
California.
If at any time, whether by virtue of any amendment of these Articles
of Incorporation or any amendment or change of the law of the State of
California relating to corporations or otherwise, any assessment shall, in any
event whatever, be levied and collected on any subscribed and issued shares of
said first preferred stock or $100 first preferred stock after the subscription
price thereof shall have been paid in full, the rights of the. owners and
holders thereof to receive dividends and their rights to share in the assets
upon the liquidation or dissolution of this corporation shall, immediately upon
the payment of such assessment and by virtue thereof, be increased in the same
ratio as the total amount of the assessment or assessments so levied and
collected shall bear to the par value of such shares of first preferred stock or
$100 first preferred stock.
RESERVES
The Board of Directors of this corporation shall, notwithstanding the
foregoing provisions of these Articles of Incorporation, have authority from
time to time to set aside, out of the profits arising from the business of this
corporation, such reasonable sums as may in their judgment be necessary and
proper for working capital and for usual reserves and surplus.
NINTH: CERTIFICATE OF DETERMINATION OF PREFERENCES OF THE 5%
REDEEMABLE FIRST PREFERRED STOCK: The Certificate of Determination of
Preferences of the 5% Redeemable First Preferred Stock which is attached hereto
as Exhibit 1 is hereby incorporated by reference as Article NINTH of these
Articles of Incorporation.
A-9
<PAGE>
TENTH: CERTIFICATE OF DETERMINATION OF PREFERENCES OF THE 5%
REDEEMABLE FIRST PREFERRED STOCK, SERIES A: The Certificate of Determination of
Preferences of the 5% Redeemable First Preferred Stock, Series A, which is
attached hereto as Exhibit 2 is hereby incorporated by reference as Article
TENTH of these Articles of Incorporation.
ELEVENTH: CERTIFICATE OF DETERMINATION OF PREFERENCES OF THE 4.80%
REDEEMABLE FIRST PREFERRED STOCK: The Certificate of Determination of
Preferences of the 4.80% Redeemable First Preferred Stock which is attached
hereto as Exhibit 3 is hereby incorporated by reference as Article ELEVENTH of
these Articles of Incorporation.
TWELFTH: CERTIFICATE OF DETERMINATION OF PREFERENCES OF THE 4.50%
REDEEMABLE FIRST PREFERRED STOCK: The Certificate of Determination of
Preferences of the 4.50% Redeemable First Preferred Stock which is attached
hereto as Exhibit 4 is hereby incorporated by reference as Article TWELFTH of
these Articles of Incorporation.
THIRTEENTH: CERTIFICATE OF DETERMINATION OF I PREFERENCES OF THE 4.36%
REDEEMABLE FIRST PREFERRED STOCK: The Certificate of Determination of
Preferences of the 4.36% Redeemable First Preferred Stock which is attached
hereto as Exhibit 5 is hereby incorporated by reference as Article THIRTEENTH of
these Articles of Incorporation.
FOURTEENTH: CERTIFICATE OF DETERMINATION OF PREFERENCES OF THE 7.44%
REDEEMABLE FIRST PREFERRED STOCK: The Certificate of Determination of
Preferences of the 7.44% Redeemable First Preferred Stock which is attached
hereto as Exhibit 6 is hereby incorporated by reference as Article I FOURTEENTH
of these Articles of Incorporation.
FIFTEENTH: CERTIFICATE OF DETERMINATION OF PREFERENCES OF THE 6.57%
REDEEMABLE FIRST PREFERRED STOCK: The Certificate of Determination of
Preferences of the 6.57% Redeemable First Preferred Stock which is attached
hereto as Exhibit 7 is hereby incorporated by reference as Article FIFTEENTH of
these Articles of Incorporation.
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<PAGE>
SIXTEENTH: CERTIFICATE OF DETERMINATION OF PREFERENCES OF THE 7.04%
REDEEMABLE FIRST PREFERRED STOCK: The Certificate of Determination of
Preferences of the 7.04% Redeemable First Preferred Stock which is attached
hereto as Exhibit S is hereby incorporated by reference as Article SIXTEENTH of
these Articles of Incorporation.
SEVENTEENTH: CERTIFICATE OF DETERMINATION OF PREFERENCES OF THE
6-7/8% REDEEMABLE FIRST PREFERRED STOCK: The Certificate of Determination of
Preferences of the 6-7/8% Redeemable First Preferred Stock which is attached
hereto as Exhibit 9 is hereby incorporated by reference as Article SEVENTEENTH
of these Articles of Incorporation.
EIGHTEENTH: CERTIFICATE OF DETERMINATION OF PREFER-ENCES OF THE 6.30%
REDEEMABLE FIRST PREFERRED STOCK: The Certificate of Determination of
Preferences of the 6.30% Redeemable First Preferred Stock which is attached
hereto as Exhibit 10 is hereby incorporated by reference as Article EIGHTEENTH
of these Articles of Incorporation.
3. The foregoing amendments and restatement of the Articles of
Incorporation of this corporation have been duly approved by the Board
of Directors.
4. The foregoing amendments and restatement of the Articles of
Incorporation were adopted (i) to eliminate Article Ninth which was
deleted upon the filing on January 1, 1997, of the Agreement of Merger
made as of December 19, 1996, by and among this corporation, PG&E
Merger Company, and PG&E Corporation, (ii) to eliminate Articles
Fifteenth, Sixteenth, and Seventeenth, which previously set forth the
Certificates of Determination of Preferences of the 7.84% Redeemable
First Preferred Stock, the 8% Redeemable First Preferred Stock, and
the 8.20% Redeemable First Preferred Stock, respectively, to reflect
the reduction in the authorized number of shares of each of those
series to zero which occurred upon filing the Certificate of Decrease
with respect to such series immediately preceding the filing of these
Restated Articles, pursuant to California Corporations Code Section
401(c)and the elimination of each of those
A-11
<PAGE>
series as an authorized series of the corporation pursuant to
California Corporations Code Section 401(f); and (iii) to renumber the
remaining Articles to reflect the deletion of Articles Ninth,
Fifteenth, Sixteenth, and Seventeenth. I
5. Pursuant to California Corporations Code Sections 202(e) (3),
203.5(b), 401(c) and 401(f), amendments to the Articles of
Incorporation for the foregoing purposes need not be approved by the
affirmative vote of the majority of the outstanding shares;
accordingly, the foregoing amendments and restatement may be adopted
with approval of the Board of Directors alone.
We further declare under penalty of perjury under the laws of the
State of California that the matters set forth in this certificate are true and
correct of our own knowledge.
Date: April 23, 1997
_____________________________
STANLEY T. SKINNER
Chairman of the Board and
Chief Executive Officer
_____________________________
LESLIE H. EVERETT
Vice president and
Corporate Secretary
A-12
<PAGE>
EXHIBIT 1
PACIFIC GAS AND ELECTRIC COMPANY
CERTIFICATE OF DETERMINATION OF PREFERENCES
OF 5% REDEEMABLE FIRST PREFERRED STOCK
WHEREAS, the Articles of Incorporation of this corporation provide for a
class of stock known as First Preferred Stock, issuable from time to time in one
or more series, of which a series of such class of stock was issued as the 5%
Redeemable First Preferred Stock, $25 par value (herein called the "5% Series");
and
WHEREAS, this corporation has elected to redeem, purchase, or otherwise
acquire 1,082,805 shares of the 5% Series from time to time; and
WHEREAS, pursuant to California Corporations Code Section 401(c), this
corporation filed a Certificate of Decrease in Number of Shares of Certain
Series of First Preferred Stock on March 23, 1994, which amended the Articles of
Incorporation to decrease the number of shares constituting the 5% Series from
2,860,977 to 1,778,172 shares; and
WHEREAS, pursuant to California Corporations Code Section 202(e) (3), the
1,082,805 shares constituting the decrease in the 5% Series resumed the status
of authorized and unissued shares of First Preferred Stock, $25 par value; and
WHEREAS, it is in the best interest of this corporation to restate the four
existing Certificates of Determination of Preferences of the 5% Series to (i)
reflect the reduction in the authorized number of shares of the 5% Series, (ii)
consolidate such existing Certificates of Determination of Preferences into a
single Certificate of Determination of Preferences of the 5% Series, and (iii)
eliminate the portions of the officers' certificates and verifications which do
not set forth any of the rights, preferences, privileges, or restrictions of the
5% Series.
A-13
<PAGE>
NOW, THEREFORE, BE IT RESOLVED that the foregoing restatement of the
Certificates of Determination of Preferences of the 5% Series is hereby
approved; and
BE IT FURTHER RESOLVED that the Certificate of Determination of Preferences
of the 5% Series is hereby approved and adopted as restated in its entirety as
follows:
1,778,172 shares of this corporation's unissued redeemable First
Preferred Stock shall constitute a series designated "5% Redeemable First
Preferred Stock"; the dividend rate of such shares shall be five per cent
per year; such shares shall have no conversion rights; and the redemption
price of such shares shall be
$28.25 per share if redeemed on or before July 31,
1953,
$27.75 per share if redeemed thereafter and on or
before July 31, 1958,
$27.25 per share if redeemed thereafter and on or
before July 31, 1963, and
$26.75 per share if redeemed thereafter.
A-14
<PAGE>
EXHIBIT 2
PACIFIC GAS AND ELECTRIC COMPANY
CERTIFICATE OF DETERMINATION OF PREFERENCES
OF 5% REDEEMABLE FIRST PREFERRED STOCK,
SERIES A
WHEREAS, the Articles of Incorporation of this corporation provide for a
class of stock known as First Preferred Stock, issuable from time to time in one
or more series, of which a series of such class of stock was issued as the 5%
Redeemable First Preferred Stock, Series A, $25 par value (herein called the "5%
Series A"); and
WHEREAS, this corporation has elected to redeem, purchase, or otherwise
acquire 815,676 shares of the 5% Series A from time to time; and
WHEREAS, pursuant to California Corporations Code Section 401(c), this
corporation filed a Certificate of Decrease in Number of Shares of Certain
Series of First Preferred Stock on March 23, 1994, which amended the Articles of
Incorporation to decrease the number of shares constituting the 5% Series A from
1,750,000 to 934,322 shares; and
WHEREAS, pursuant to California Corporations Code Section 202(e) (3), the
815,678 shares constituting the decrease in the 5% Series A resumed the status
of authorized and unissued shares of First Preferred Stock, $25 par value; and
WHEREAS, it is in the best interest of this corporation to restate the two
existing Certificates of Determination of Preferences of the 5% Series A to (i)
reflect the reduction in the authorized number of shares of the 5% Series A,
(ii) consolidate such existing Certificates of Determination of Preferences into
a single Certificate of Determination of Preferences of the 5% Series A, and
(iii) eliminate the portions of the officers' certificates and verifications
which do not set forth any of the rights, preferences, privileges, or
restrictions of the 5% Series A.
A-15
<PAGE>
NOW, THEREFORE, BE IT RESOLVED that the foregoing restatement of the
Certificates of Determination of Preferences of the 5% Series A is hereby
approved; and
BE IT FURTHER RESOLVED that the Certificate of Determination of Preferences
of the 5% Series A is hereby approved and adopted as restated in its entirety as
follows:
934,322 shares of this corporation's unissued redeemable First
Preferred Stock shall constitute a series designated "5% Redeemable First
Preferred Stock, Series A'~; the dividend rate of such shares shall be five
per cent per year; such shares shall have no conversion rights; and the
redemption price of such shares shall be
$28.25 per share if redeemed on or before July 31,
1953,
$27.75 per share if redeemed thereafter and on or
before July 31, 1958,
$27.25 per share if redeemed thereafter and on or
before July 31, 1963, and
$26.75 per share if redeemed thereafter.
A-16
<PAGE>
EXHIBIT 3
PACIFIC GAS AND ELECTRIC COMPANY CERTIFICATE OF DETERMINATION OF
PREFERENCES OF 4.80% REDEEMABLE FIRST PREFERRED STOCK
WHEREAS, the Articles of Incorporation of this corporation provide for a
class of stock known as First Preferred Stock, issuable from time to time in one
or more series, of which a series of such class of stock was issued as the 4.80%
Redeemable First Preferred Stock, $25 par value (herein called the "4.80%
Series"); and
WHEREAS, this corporation has elected to redeem, purchase, or otherwise
acquire 724,344 shares of the 4.80% Series from time to time; and
WHEREAS, pursuant to California Corporations Code Section 401(c), this
corporation filed a Certificate of Decrease in Number of Shares of Certain
Series of First Preferred Stock on March 23, 1994, which amended the Articles of
Incorporation to decrease the number of shares constituting the 4.80% Series
from 1,517,375 to 793,031 shares; and
WHEREAS, pursuant to California Corporations Code Section 202(e) (3), the
724,344 shares constituting the decrease in the 4.80% Series resumed the status
of authorized and unissued shares of First Preferred Stock, $25 par value; and
WHEREAS, it is in the best interest of this corporation to restate the two
existing Certificates of Determination of Preferences of the 4.80% Series to (i)
reflect the reduction in the authorized number of shares of the 4.80% Series,
(ii) consolidate such existing Certificates of Determination of Preferences into
a single Certificate of Determination of Preferences of the 4.80% Series, and
(iii) eliminate the portions of the officers certificates and verifications
which do not set forth any of the rights, preferences, privileges, or
restrictions of the 4.80% Series.
A-17
<PAGE>
NOW, THEREFORE, BE IT RESOLVED that the foregoing restatement of the
Certificates of Determination of Preferences of the 4.80% Series is hereby
approved; and
BE IT FURTHER RESOLVED that the Certificate of Determination of Preferences
of the 4.80% Series is hereby approved and adopted as restated in its entirety
as follows:
793,031 shares of this corporation's unissued redeemable First
Preferred Stock shall constitute a series designated "4.80% Redeemable
First Preferred Stock"; the dividend rate of such shares shall be 4.60% per
year; such shares shall have no conversion rights; and the redemption price
for such shares shall be
$28.75 per share if redeemed on or before January 31,
1955;
$28.25 per share if redeemed thereafter and on or
before January 31, 1960;
$27.75 per share if redeemed thereafter and on or
before January 31, 1965; and
$27.25 per share if redeemed thereafter.
A-18
<PAGE>
EXHIBIT 4
PACIFIC GAS AND ELECTRIC COMPANY
CERTIFICATE OF DETERMINATION OF PREFERENCES
OF 4.50% REDEEMABLE FIRST PREFERRED STOCK
WHEREAS, the Articles of Incorporation of this corporation provide for a
class of stock known as First Preferred Stock, issuable from time to time in one
or more series, of which a series of such class of stock was issued as the 4.50%
Redeemable First Preferred Stock, $25 par value (herein called the "4.50%
Series"); and
WHEREAS, this corporation has elected to redeem, purchase, or otherwise
acquire 516,284 shares of the 4.50% Series from time to time; and
WHEREAS, pursuant to California Corporations Code Section 401(c), this
corporation filed a Certificate of Decrease in Number of Shares of Certain
Series of First Preferred Stock on March 23, 1994, which amended the Articles of
Incorporation to decrease the number of shares constituting the 4.50% Series
from 1,127,426 to 611,142 shares; and
WHEREAS, pursuant to California Corporations Code Section 202(e) (3), the
516,284 shares constituting the decrease in the 4.50% Series resumed the status
of authorized and unissued shares of First Preferred Stock, $25 par value; and
WHEREAS, it is in the best interest of this corporation to restate the two
existing Certificates of Determination of Preferences of the 4.50% Series to (i)
reflect the reduction in the authorized number of shares of the 4.50% Series,
(ii) consolidate such existing Certificates of Determination of Preferences into
a single Certificate of Determination of Preferences of the 4.50% Series, and
(iii) eliminate the portions of the officers' certificates and verifications
which do not set forth any of the rights, preferences, privileges, or
restrictions of the 4.50% Series.
NOW, THEREFORE, BE IT RESOLVED that the foregoing restatement of the
Certificates of Determination of Preferences of the 4.50% Series is hereby
approved; and
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<PAGE>
BE IT FURTHER RESOLVED that the Certificate of Determination of
Preferences of the 4.50% Series is hereby approved and adopted as restated in
its entirety as follows:
611,142 shares of this corporation's unissued redeemable first
preferred stock shall constitute a series designated "4.50% Redeemable
First Preferred Stock"; the dividend rate of such shares shall be 4.50% per
year; such shares shall have no conversion rights; and the redemption price
of such shares shall be
$27.25 per share if redeemed on or before July 31, 1959;
$26.75 per share if redeemed thereafter and on or before
July 31, 1964;
$26.25 per share if redeemed thereafter and on or before
July 31, 1969; and
$26.00 per share if redeemed thereafter.
A-20
<PAGE>
EXHIBIT 5
PACIFIC GAS AND ELECTRIC COMPANY
CERTIFICATE OF DETERMINATION OF PREFERENCES
OF 4.36% REDEEMABLE FIRST PREFERRED STOCK
WHEREAS, the Articles of Incorporation of this corporation provide for a
class of stock known as First Preferred Stock, issuable from time to time in one
or more series, of which a series of such class of stock was issued as the
.4.36% Redeemable First Preferred Stock, $25 par value (herein called the "4.36%
Series"); and
WHEREAS, this corporation has elected to redeem, purchase or otherwise
acquire 561,709 shares of the 4.36% Series from time to time; and
WHEREAS, pursuant to California Corporations Code Section 401(c), this
corporation filed a Certificate of Decrease in Number of Shares of Certain
Series of First Preferred Stock on March 23, 1994, which amended the Articles of
Incorporation to decrease the number of shares constituting the 4.36% Series
from 1,000,000 to 418,291 shares; and
WHEREAS, pursuant to California Corporations Code Section 202(e) (3), the
581,709 shares constituting the decrease in the 4.36% Series resumed the status
of authorized and unissued shares of First Preferred Stock, $25 par value; and
WHEREAS, it is in the best interest of this corporation to restate the
Certificate of Determination of Preferences of the 4.36% Series to (i) reflect
the reduction in the authorized number of shares of the 4.36% Series and (ii)
eliminate the portions of the officers' certificate and verification which do
not set forth any of the rights, preferences, privileges, or restrictions of the
4.36% Series.
NOW, THEREFORE, BE IT RESOLVED that the foregoing restatement of the
Certificate of Determination of Preferences of the 4.36% Series is hereby
approved; and
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<PAGE>
BE IT FURTHER RESOLVED that the Certificate of Determination of Preferences
of the 4.36% Series is hereby approved and adopted as restated in its entirety
as follows:
418,291 shares of this corporation's unissued Redeemable First Preferred Stock
shall constitute a series designated "4.36% Redeemable First Preferred Stock";
the dividend rate of such shares shall be 4.36% per year; such shares shall
have no conversion rights; and the redemption price of such shares shall be
$26.75 per share if redeemed on or before October 31,
1960;
$26.50 per share if redeemed thereafter and on or before
October 31, 1965;
$26.25 per share if redeemed thereafter and on or before
October 31, 1970;
$26.00 per share if redeemed thereafter and on or before
October 31, 1975; and
$25.75 per share if redeemed thereafter.
A-22
<PAGE>
EXHIBIT 6
CERTIFICATE OF DETERMINATION OF PREFERENCES
OF 7.44% REDEEMABLE FIRST PREFERRED STOCK OF
PACIFIC GAS AND ELECTRIC COMPANY
WHEREAS, the Articles of Incorporation of this corporation provide for a
class of stock known as First Preferred Stock, issuable from time to time in one
or more series, of which a series of such class of stock was issued as the 7.44%
Redeemable First Preferred Stock, ~25 par value (herein called the '7.44%
Series"); and
WHEREAS, it is in the best interest of this corporation to restate the
Certificate of Determination of Preferences of the 7.44% Series to eliminate the
portions of the officers' certificate and verification which do not set forth
any of the rights, preferences, privileges, or restrictions of the 7.44% Series.
NOW, THEREFORE, BE IT RESOLVED that the foregoing restatement of the
Certificate of Determination of Preferences of the 7.44% Series is hereby
approved; and
BE IT FURTHER RESOLVED, that the Certificate of Determination of
Preferences of the 7.44% Series is hereby approved and adopted as restated in
its entirety as follows:
5,000,000 shares of this corporation' 5 unissued First Preferred Stock, $25
par value, shall constitute a series designated "7.44% Redeemable First
Preferred Stock"; the dividend rate of such shares shall be 7.44% of the par
value per year; such shares shall have no conversion rights; and the redemption
price of such shares shall be $25.00, provided that none of such shares shall be
redeemed prior to August 1, 1997, for any purpose.
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<PAGE>
EXHIBIT 7
CERTIFICATE OF DETERMINATION OF PREFERENCES
OF 6.57% REDEEMABLE FIRST PREFERRED STOCK OF
PACIFIC GAS AND ELECTRIC COMPANY
WHEREAS, the Articles of Incorporation of this corporation provide for a
class of stock known as First Preferred Stock, issuable from time to time in one
or more series, of which a series of such class of stock was issued as the 6.57%
Redeemable First Preferred Stock, $25 par value (herein called the "6.57%
Series"); and
WHEREAS, it is in the best interest of this corporation to restate the
Certificate of Determination of Preferences of the 6.57% Series to eliminate the
portions of the officers' certificate and verification which do not set forth
any of the rights, preferences, privileges, or restrictions of the 6.57% Series.
NOW, THEREFORE, BE IT RESOLVED that the foregoing restatement of the
Certificate of Determination of Preferences of the 6.57% Series is hereby
approved; and
BE IT FURTHER RESOLVED that the Certificate of Determination of Preferences
of the 6.57% Series is hereby approved and adopted as restated in its entirety
as follows:
3,000,000 shares of this corporation's unissued First Preferred Stock,
$25 par value, shall constitute a series designated "6.57% Redeemable First
Preferred Stock" (hereinafter referred to as the "6.57% Series")
The terms of the 6.57% Series are hereby fixed as follows:
(a) The holders of shares of the 6.57% Series shall be entitled to
receive, when and as declared by the Board of Directors, dividends at
the rate of 6.57 percent of par value thereof per annum, and no more.
Such dividends shall be cumulative with respect to each share from the
date of issuance thereof.
(b) No dividend shall be declared or paid on any shares of the 6.57%
Series or on any shares of any other series or class of preferred
stock unless a
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<PAGE>
ratable dividend on the 6.57% Series and such other series or class of
preferred stock, in proportion to the full preferential amounts to
which each series or class is entitled, is declared and is paid or set
apart for payment. As used herein, the term "preferred stock" shall
mean all series of the first preferred stock, $25 par value per share,
and first preferred stock, $100 par value per share, and any other
class of stock ranking equally with the preferred stock as to
preference in dividends and liquidation rights, notwithstanding that
shares of such series and classes may differ as to the amounts of
dividends or liquidation payments to which they are entitled.
(c) No junior shares or shares of preferred stock shall be purchased,
redeemed or otherwise acquired by the corporation, and no moneys shall
be paid to or set aside or made available for a sinking fund for the
purchase or redemption of junior shares or shares of preferred stock,
unless full cumulative dividends upon all series and classes of
preferred stock then outstanding to the end of the dividend period
next preceding the date fixed for such redemption (and for the current
dividend period if the date fixed for such redemption is a dividend
payment date) shall have been declared and shall have been paid or set
aside for payment. As used herein, the term "junior shares" shall
mean common shares or any other shares ranking junior to the preferred
stock either as to dividends or upon liquidation, dissolution, or
winding up.
(d) The shares of the 6.57% Series shall not be subject to redemption
by this corporation prior to July 31, 2002. On or after July 31,
2002, the redemption price shall be $25.00 per share, together with an
amount equal to all accumulated and unpaid dividends thereon to and
including the date of redemption.
(e) Shares of the 6.57% Series shall also be subject to redemption
through the operation of a sinking fund (herein called the "Sinking
Fund") at the redemption price (the "Sinking Fund Redemption Price")
of $25.00 per share plus an amount equal to the accumulated and unpaid
dividends thereon to and including the
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<PAGE>
redemption date, whether or not earned or declared. For the purposes
of the Sinking Fund, out of any funds of the corporation legally
available therefor remaining after full cumulative dividends upon all
series and classes of preferred stock then outstanding to the end of
the dividend period next preceding the date fixed for such redemption
(and for the current dividend period if the date fixed for such
redemption is a dividend payment date) shall have been declared and
shall have been paid or set apart for payment, the corporation shall
redeem 150,000 shares of the 6.57% Series annually on each July 31,
from 2002 through 2006, inclusive, and 2,250,000 shares on July 31,
2007, at the Sinking Fund Redemption Price. The Sinking Fund shall be
cumulative so that if on any such July 31 the funds of the corporation
legally available therefor shall be insufficient to permit the
required redemption in full, or if for any other reason such
redemption shall not have been made in full, the remaining shares of
the 6.57% Series so required to be redeemed shall be redeemed before
any cash dividend shall be paid or declared, or any distribution made,
on any junior shares or before any junior shares or any shares of
preferred stock shall be purchased, redeemed or otherwise acquired by
the corporation, or any monies shall be paid to or set aside or made
available for a sinking fund for the purchase or redemption or any
junior shares or any shares of preferred stock; provided, however,
that, notwithstanding the existence of any such deficiency, the
corporation may make any required sinking fund redemption on any otter
series or class of preferred stock if the number of shares of such
other series or class of preferred stock being so redeemed bears (as
nearly as practicable) the same ratio to the aggregate number of
shares of such other series or class then due to be redeemed as the
number of shares of the 6.57% Series being redeemed bears to the
aggregate number of shares of the 6.57% Series then due to be
redeemed.
(f) Shares of the 6.57% Series redeemed otherwise than as required by
section (e) or purchased or otherwise acquired by the corporation may,
at the option of the corporation, be applied as a credit against any
Sinking Fund redemption required by
A-26
<PAGE>
section (e). Moneys available for the Sinking Fund shall be applied
on each such July 31 to the redemption of shares of the 6.57% Series.
(g) Any shares of the 6.57% Series which have been redeemed,
purchased, or otherwise acquired by the corporation shall become
authorized and unissued shares of the First Preferred Stock, $25 par
value, but shall not be reissued as shares of the 6.57% Series.
(h) Upon liquidation, dissolution, or winding up of the corporation,
the holders of shares of the 6.57% Series shall be entitled to receive
the liquidation value per share, which is hereby fixed at $25.00 per
share, plus an amount equal to all accumulated and unpaid dividends
thereon at such time, whether or not earned or declared.
(i) Dividends shall be computed on a basis of a 360-day year of
twelve 30-day months.
(j) If the date for payment of any dividend or the date fixed for
redemption of any share of the 6.57% Series shall not be on a business
day, then payment of the dividend or applicable redemption price need
not be made on such date, but may be made on the next succeeding
business day with the same force and effect as if made on the date for
payment of such dividend or date fixed for redemption.
A-27
<PAGE>
EXHIBIT 8
CERTIFICATE OF DETERMINATION OF PREFERENCES
OF 7.04% REDEEMABLE FIRST PREFERRED STOCK OF
PACIFIC GAS AND ELECTRIC COMPANY
WHEREAS, the Articles of Incorporation of this corporation provide for a
class of stock known as First Preferred Stock, issuable from time to time in one
or more series, of which a series of such class of stock was issued as the 7.04%
Redeemable First Preferred Stock, $25 par value (herein called the "7.04%
Series"); and
WHEREAS, it is in the best interest of this corporation to restate the
Certificate of Determination of Preferences of the 7.04% Series to eliminate the
portions of the officers' certificate and verification which do not set forth
any of the rights, preferences, privileges, or restrictions of the 7.04% Series.
NOW, THEREFORE, BE IT RESOLVED that the foregoing restatement of the
Certificate of Determination of Preferences of the 7.04% Series is hereby
approved; and
BE IT FURTHER RESOLVED that the Certificate of Determination of Preferences
of the 7.04% Series is hereby approved and adopted as restated in its entirety
as follows:
3,000,000 shares of this corporation's unissued First Preferred Stock,
$25 par value, shall constitute a series designated "7.04% Redeemable First
Preferred Stock" (hereinafter referred to as the "7.04% Series")
The terms of the 7.04% Series are hereby fixed as follows
(a) The holders of shares of the 7.04% Series shall be entitled to
receive, when and as declared by the Board of Directors, dividends at
the rate of 7.04 percent of par value thereof per annum, and no more.
Such dividends shall be cumulative with respect to each share from the
date of issuance thereof.
(b) No dividend shall be declared or paid on any shares of the 7.04%
Series or on any shares of any other series or class of preferred
stock unless a ratable dividend on the 7.04% Series and such other
series or class of preferred stock, in proportion to the full
preferential amounts to which each series or class is entitled, is
declared and is paid or set apart for payment. As used herein, the
term "preferred stock" shall mean all series
A-28
<PAGE>
of the first preferred stock, $25 par value per share, and first
preferred stock, $100 par value per share, and any other class of
stock ranking equally with the preferred stock as to preference in
dividends and liquidation rights, notwithstanding that shares of such
series and classes may differ as to amounts of dividends or
liquidation payments to which they are entitled.
(c) No junior shares or shares of preferred stock shall be purchased,
redeemed, or otherwise acquired by the corporation, and no moneys
shall be paid to or set aside or made available for a sinking fund for
the purchase or redemption of junior shares or shares of preferred
stock, unless full cumulative dividends upon all series and classes of
preferred stock then outstanding to the end of the dividend period
next preceding the date fixed for such redemption (and for the current
dividend period if the date fixed for such redemption is a dividend
payment date) shall have been declared and shall have been paid or set
aside for payment. As used herein, the term "junior shares" shall
mean common shares or any other shares ranking junior to the preferred
stock either as to dividends or upon liquidation, dissolution, or
winding up.
(d) The shares of the 7.04% Series shall not be subject to redemption
by this corporation prior to January 31, 2003. On and after January
31. 2003, the redemption price shall be as follows:
<TABLE>
<CAPTION>
If redeemed during the 12 months' period beginning January 31,
<S> <C> <C> <C>
2003 $25.68 2006 $25.44
2004 $25.79 2009 $25.35
2005 $25.70 2010 $25.26
2006 $25.62 2011 $25.18
2007 $25.53 2012 $25.09
</TABLE>
and at $25.00 per share on and after January 31, 2013, together in
each case with an amount equal to all accumulated and unpaid dividends
thereon to and including the date of redemption. For the purpose of
redeeming any shares of the 7.04% Series, payment of the redemption
price shall be out of any funds of the corporation legally available
therefor remaining after: (i) full cumulative dividends upon all
series and classes of preferred stock then outstanding to the end of
the dividend period next preceding the date fixed for
A-29
<PAGE>
such redemption (and for the current dividend period if the date fixed
for such redemption is a dividend payment date) shall have been
declared and shall have been paid or set apart for payment, and (ii)
all money shall have been paid to or set aside or made available for
any sinking fund for the purchase or redemption of all series of and
classes of preferred stock as may be required by the terms of such
preferred stock.
(e) Any shares of the 7.04% Series which have been redeemed,
purchased, or otherwise acquired by the corporation shall become
authorized and unissued shares of the First Preferred Stock, $25 par
value, but shall not be reissued as shares of the 7.04% Series.
(f) Upon liquidation, dissolution, or winding up of the corporation,
the holders of shares of the 7.04% Series shall be entitled to receive
the liquidation value per share, which is hereby fixed at $25.00 per
share, plus an amount equal to all accumulated and unpaid dividends
thereon at such time, whether or not earned or declared.
(g) Dividends shall be computed on a basis of a 3E0-day year of
twelve 30-day months.
(h) If the date for payment of any dividend or the date fixed for
redemption of any share of the 7.04% Series shall not be a business
day, then payment of the dividend or applicable redemption price need
not be made on such date, but may be made on the next succeeding
business day with the same force and effect as if made on the date for
payment of such dividend or date fixed for redemption.
A-30
<PAGE>
CERTIFICATE OF DETERMINATION OF PREFERENCES
OF 6-7/8% REDEEMABLE FIRST PREFERRED STOCK OF
PACIFIC GAS AND ELECTRIC COMPANY
WHEREAS, the Articles of Incorporation of this corporation provide for a
class of stock known as First Preferred Stock, issuable from time to time in one
or more series, of which a series of such class of stock was issued as the
6-7/8% Redeemable First Preferred Stock, $25 par value (herein called the
"6-7/8% Series"); and
WHEREAS, it is in the best interest of this corporation to restate the
Certificate of Determination of Preferences of the 6-7/8% Series to eliminate
the portions of the officers' certificate and verification which do not set
forth any of the rights, preferences, privileges, or restrictions of the 6-7/8%
Series.
NOW, THEREFORE, BE IT RESOLVED that the foregoing restatement of the
Certificate of Determination of Preferences of the 6-7/8% Series is hereby
approved; and
BE IT FURTHER RESOLVED that the Certificate of Determination of Preferences
of the 6-7/8% Series is hereby approved and adopted as restated in its entirety
as follows:
5,000,000 shares of this corporation's unissued Redeemable First
Preferred Stock, $25 par value, shall constitute a series designated
"6-7/8% Redeemable First Preferred Stock" (hereinafter referred to as the
"6-7/8% Series")
The terms of the 6-7/8% Series are hereby fixed as follows:
(a) The holders of shares of the 6-7/8% Series shall be entitled to
receive, when and as declared by the Board of Directors, dividends at
the rate of 6-7/6 percent of par value thereof per annum, and no more.
Such dividends shall be cumulative with respect to each share from the
date of issuance thereof.
(b) No dividend shall be declared or paid on any shares of the 6-7/8%
Series or on any shares of any other
A-31
<PAGE>
series or class of preferred stock unless a ratable dividend on the
6-7/8% Series and such other series or class of preferred stock, in
proportion to the full preferential amounts to which each series or
class is entitled, is declared and is paid or set apart for payment.
As used herein, the term "preferred stock" shall mean all series of
the first preferred stock, $25 par value per share, and first
preferred stock, $100 par value per share, and any other class of
stock ranking equally with the preferred stock as to preference in
dividends and liquidation rights, notwithstanding that shares of such
series and classes may differ as to amounts of dividends or
liquidation payments to which they are entitled.
(c) No junior shares or shares of preferred stock shall be purchased,
redeemed, or otherwise acquired by the corporation, and no moneys
shall be paid to or set aside or made available for a sinking fund for
the purchase or redemption of junior shares or shares of preferred
stock, unless full cumulative dividends upon all series and classes of
preferred stock then outstanding to the end of the dividend period
next preceding the date fixed for such redemption (and for the current
dividend period if the date fixed for such redemption is a dividend
payment date) shall have been declared and shall have been paid or set
aside for payment. As used herein, the term "junior shares" shall
mean common shares or any other shares ranking junior to the preferred
stock either as to dividends or upon liquidation, dissolution, or
winding up.
(d) The shares of the 6-7/8% Series shall not be subject to
redemption by this corporation prior to July 31, 1998. On and after
July 31, 1998, the redemption price shall be $25.00 per share,
together with an amount equal to all accumulated and unpaid dividends
thereon to and including the date of redemption. For the purpose of
redeeming any shares of the 6-7/8% Series, payment of the redemption
price shall be out of any funds of the corporation legally available
therefor remaining after: (i) full cumulative dividends upon all
series and classes of preferred stock then outstanding to the end of
the dividend period next preceding the date fixed for such redemption
(and for the current dividend period if the date fixed for such
redemption is a dividend payment
A-32
<PAGE>
date) shall have been declared and shall have been paid or set apart
for payment, and (ii) all money shall have been paid to or set aside
or made available for any sinking fund for the purchase or redemption
of all series of and classes of preferred stock as may be required by
the terms of such preferred stock.
(e) Any shares of the 6-7/8% Series which have been redeemed,
purchased, or otherwise acquired by the corporation shall become
authorized and unissued shares of the First Preferred Stock, $25 par
value, but shall not be reissued as shares of the 6-7/8% Series.
(f) Upon liquidation, dissolution, or winding up of the corporation,
the holders of shares of the 6-7/8% Series shall be entitled to
receive the liquidation value per share, which is hereby fixed at
$25.00 per share, plus an amount equal to all accumulated and unpaid
dividends thereon at such time, whether or not earned or declared.
(g) Dividends shall be computed on a basis of a 360-day year of twelve
30-day months.
(h) If the date for payment of any dividend or the date fixed for
redemption of any share of the 6-7/8% Series shall not be a business
day, then payment of the dividend or applicable redemption price need
not be made on such date, but may be made on the next succeeding
business day with the same force and effect as if made on the date for
payment of such dividend or date fixed for redemption.
A-33
<PAGE>
EXHIBIT 10
CERTIFICATE OF DETERMINATION or PREFERENCES
OF 6.30% REDEEMABLE FIRST PREFERRED STOCK OF
PACIFIC GAS AND ELECTRIC COMPANY
WHEREAS, the Articles of Incorporation of this corporation provide for a
class of stock known as First Preferred Stock, issuable from time to time in one
or more series, of which a series of such class of stock was issued as the 6.30%
Redeemable First Preferred Stock, $25 par value (herein called the "6.30%
Series"); and
WHEREAS, it is in the best interest of this corporation to restate the
Certificate of Determination of Preferences of the 6.30% Series to eliminate the
portions of the officers' certificate and verification which do not set forth
any of the rights, preferences, privileges, or restrictions of the 6.30% Series.
NOW, THEREFORE, BE IT RESOLVED that the foregoing restatement of the
Certificate of Determination of Preferences of the 6.30% Series is hereby
approved; and
BE IT FURTHER RESOLVED, that the Certificate of Determination of
Preferences of the 6.30% Series is hereby approved and adopted as restated in
its entirety as follows:
2,500,000 shares of this corporation's unissued Redeemable First
Preferred Stock, $25 par value, shall constitute a series designated "6.30%
Redeemable First Preferred Stock" (hereinafter referred to as the "6.30%
Series")
The terms of the 6.30% Series are hereby fixed as follows:
(a) The holders of shares of the 6.30% Series shall be entitled to
receive, when and as declared by the Board of Directors, dividends at
the rate of 6.30 percent of par value thereof per annum, and no more.
Such dividends shall be cumulative with respect to each share from the
date of issuance thereof.
A-34
<PAGE>
(b) No dividend shall be declared or paid on any shares of the 6.30%
Series or on any shares of any other series or class of preferred
stock unless a ratable dividend on the 6.30% Series and such other
series or class of preferred stock, in proportion to the full
preferential amounts to which each series or class is entitled, is
declared and is paid or set apart for payment. As used herein, the
term "preferred stock" shall mean all series of the first preferred
stock, $25 par value per share, and first preferred stock, $100 par
value per share, and any other class of stock ranking equally with the
preferred stock as to preference in dividends and liquidation rights,
notwithstanding that shares of such series and classes may differ as
to amounts of dividends or liquidation payments to which they are
entitled.
(c) No junior shares or shares of preferred stock shall be purchased,
redeemed, or otherwise acquired by the corporation, and no moneys
shall be paid to or set aside or made available for a sinking fund for
the purchase or redemption of junior shares or shares of preferred
stock, unless full cumulative dividends upon all series and classes of
preferred stock then outstanding to the end of the dividend period
next preceding the date fixed for such redemption (and for the current
dividend period if the date fixed for such redemption is a dividend
payment date) shall have been declared and shall have been paid or set
aside for payment. As used herein, the term "junior shares" shall
mean common shares or any other shares ranking junior to the preferred
stock either as to dividends or upon liquidation, dissolution, or
winding up.
(d) The shares of the 6.30% Series shall not be subject to redemption
by this corporation prior to January 31, 2094. On and after January
31, 2004, the redemption price shall be $2S.00 per share, together
with an amount equal to all accumulated and unpaid dividends thereon
to and including the date of redemption. For the purpose of redeeming
any shares of the 6.30% Series, payment of the redemption price shall
be out of any funds of the corporation legally available therefor
remaining after: (i) full cumulative dividends upon all series and
classes of preferred stock then outstanding to the end of the dividend
period next preceding the date fixed for such redemption (and for the
current dividend period if
A-35
<PAGE>
the date fixed for such redemption is a dividend payment date) shall
have been declared and shall have been paid or set apart for payment,
and (ii) all money shall have been paid to or set aside or made
available for any sinking fund for the purchase or redemption of all
series of and classes of preferred stock as may be required by the
terms of such preferred stock.
(e) Shares of the 6.30% Series shall also be subject to redemption
through the operation of a sinking fund (herein called the "Sinking
Fund") at the redemption price (the "Sinking Fund Redemption Price")
of $25.00 per share plus an amount equal to the accumulated and unpaid
dividends thereon to and including the redemption date, whether or not
earned or declared. For the purposes of the Sinking Fund, out of any
funds of the corporation legally available therefor remaining after
full cumulative dividends upon all series and classes of preferred
stock then outstanding to the end of the dividend period next
preceding the date fixed for such redemption (and for the current
dividend period if the date fixed for such redemption is a dividend
payment date) shall have been declared and shall have been paid or set
apart for payment, the corporation shall redeem C) 125,000 shares of
the 6.30% Series annually on each January 31, from 2004 through 2008,
inclusive, and 1,875,000 shares on January 31, 2009, at the Sinking
Fund Redemption Price. The Sinking Fund shall be cumulative so that if
on any such January 31 the funds of the corporation legally available
therefor shall be insufficient to permit the required redemption in
full, or if for any other reason such redemption shall not have been
made in full, the remaining shares of the 6.30% Series so required to
be redeemed shall be redeemed before any cash dividend shall be paid
or declared, or any distribution made, on any junior shares or before
any junior shares or any shares of preferred stock shall be purchased,
redeemed or otherwise acquired by the corporation, or any moneys shall
be paid to or set aside or made available for a sinking fund for the
purchase or redemption of any junior shares or any shares of preferred
stock; provided, however, that, notwithstanding the existence of any
such deficiency, the corporation may make any required sinking fund
redemption on any other series or class of preferred stock if the
number of shares of such other series or
A-36
<PAGE>
class of preferred stock being so redeemed bears (as nearly as
practicable) the same ratio to the aggregate number of shares of such
other series or class then due to be redeemed as the number of shares
of the 6.30% Series being redeemed bears to the aggregate number of
shares of the 6.30% Series then due to be redeemed.
(f) Shares of the 6.30% Series redeemed otherwise than as required by
section (e) or purchased or otherwise acquired by the corporation may,
at the option of the corporation, be applied as a credit against any
Sinking Fund redemption required by section (e). Moneys available for
the Sinking Fund shall be applied on each such January 31 to the
redemption of shares of the 6.30% Series.
(g) Any shares of the 6.30% Series which have been redeemed,
purchased, or otherwise acquired by the corporation shall become
authorized and unissued shares of the First Preferred Stock, $25 par
value, but shall not be reissued as shares of the 6.30% Series.
(h) Upon liquidation, dissolution, or winding up of the corporation,
the holders of shares of the 6.30% Series shall be entitled to receive
the liquidation value per share, which is hereby fixed at $25.00 per
share, plus an amount equal to all accumulated. and unpaid dividends
thereon at such time, whether or not earned or declared.
(i) Dividends shall be computed on a basis of a 360-day year of twelve
30-day months.
(j) If the date for payment of any dividend or the date fixed for
redemption of any share of the 6.30% Series shall not be a business
day, then payment of the dividend or applicable redemption price need
not be made on such date, but may be made on the next succeeding
business day with the same force and effect as if made on the date for
payment of such dividend or date fixed for redemption.
A-37
<PAGE>
EXHIBIT B
BALANCE SHEET AND INCOME STATEMENT
24
<PAGE>
PACIFIC GAS & ELECTRIC COMPANY
BALANCE SHEET
DECEMBER 31, 1996
ASSETS AND OTHER DEBITS
-----------------------
(000'S Omitted)
<TABLE>
<CAPTION>
LINE LINE
NO. UTILITY PLANT NO.
<C> <S> <C> <C>
1 Utility Plant $31,229,188 1
2 Construction Work in Progress 399,738 2
3 Total Utility Plant 31,628,926 3
Less: Accumulated Provision for Depreciation and
4 Amortization 13,872,121 4
5 Net Utility Plant 17,756,805 5
6 Nuclear Fuel 948,028 6
Less: Accumulated Provision for Amortization of
7 Nuclear Fuel Assemblies 757,376 7
8 Net Nuclear Fuel 190,652 8
9 Net Utility Plant 17,947,457 9
10 Gas Stored Underground - Noncurrent 47,426 10
OTHER PROPERTY AND INVESTMENTS
11 Nonutility Property 28,456 11
12 Investment in Subsidiary Companies 1,212,575 12
13 Other Investments 8,370 13
14 Special Funds 914,553 14
15 Total Other Property and Investments 2,163,954 15
CURRENT AND ACCRUED ASSETS
16 Cash 46,767 16
17 Special Deposits 9,314 17
18 Working Fund 1,113 18
19 Temporary Cash Investments 0 19
20 Notes Receivable 14 20
21 Customers Accounts Receivable 662,515 21
22 Other Accounts Receivable 18,586 22
23 Less: Accumulated Provision for Uncollectible Accounts (56,068) 23
24 Accounts Receivable from Associated Companies 6,609 24
25 Fuel Stock 23,433 25
26 Plant Materials and Operating Supplies 177,038 26
27 Gas Stored Underground - Current 127,771 27
28 Prepayments 26,165 28
29 Interest and Dividends Receivable 0 29
30 Accrued Utility Revenues 418,761 30
31 Total Current and Accrued Assets 1,462,018 31
DEFERRED DEBITS
32 Unamortized Debt Expenses 41,437 32
33 Unrecovered Plant and Regulatory Study Costs 4,896 33
34 Other Regulatory Assets 3,861,232 34
35 Preliminary Survey and Investigation Charges (Electric) 0 35
36 Preliminary Survey and Investigation Charges (Gas) 0 36
37 Clearing Accounts (1) 37
38 Temporary Facilities (4,159) 38
39 Miscellaneous Deferred Debits 21,448 39
40 Unamortized Loss on Reacquired Debt 366,193 40
41 Accumulated Deferred Income Taxes 1,313,754 41
42 Total Deferred Debits 5,604,800 42
43 Total Assets and Other Debits $27,225,655 43
</TABLE>
( ) Denotes Deduction B-1
B-1
<PAGE>
EXHIBIT B
PACIFIC GAS & ELECTRIC COMPANY
BALANCE SHEET
DECEMBER 31, 1996
LIABILITIES AND OTHER CREDITS
-----------------------------
(000'S Omitted)
<TABLE>
<CAPTION>
LINE LINE
NO. PROPRIETARY CAPITAL NO.
<C> <S> <C> <C>
1 Common Stock Issued $ 2,017,522 1
2 Preferred Stock Issued 539,556 2
3 Premium on Capital Stock 3,765,098 3
4 Less: Discount on Capital Stock (6,917) 4
5 Less: Capital Stock Expense (48,288) 5
6 Retained Earnings 2,578,005 6
7 Unappropriated Undistributed Subsidiary Earnings 57,882 7
8 Total Proprietary Capital 8,902,858 8
----------
LONG-TERM DEBT
9 Bonds 5,585,272 9
10 Less: Reacquired Bonds (164,951) 10
11 Advances from Associated Companies 309,278 11
12 Other Long-Term Debt 1,907,107 12
13 Unamortized Premium on Long-Term Debt 1 13
14 Less:Unamortized Discount on Long-Term Debt (51,110) 14
----------
15 Total Long-term Debt 7,585,597 15
----------
OTHER NONCURRENT LIABILITIES
16 Obligations Under Capital Leases - Noncurrent 11,526 16
17 Accumulated Provision for Injuries and Damages 388,007 17
18 Accumulated Provision for Pensions and Benefits 114,318 18
19 Accumulated Miscellaneous Operating Provisions 551,307 19
20 Accumulated Provision for Rate Refunds 7,561 20
----------
21 Total Other Noncurrent Liabilities 1,072,719 21
----------
CURRENT AND ACCRUED LIABILITIES
22 Notes Payable 680,900 22
23 Accounts Payable 782,258 23
24 Accounts Payable to Associated Companies 152,029 24
25 Customer Deposits 50,957 25
26 Taxes Accrued 294,840 26
27 Interest Accrued 69,641 27
28 Dividends Declared 123,310 28
29 Matured Long-Term Debt 1,139 29
30 Matured Interest 120 30
31 Tax Collections Payable 17,323 31
32 Miscellaneous Current and Accrued Liabilities 273,385 32
33 Obligations Under Capital Leases - Current 524 33
34 Total Current and Accrued Liabilities 2,446,426 34
DEFERRED CREDITS
35 Customer Advances for Construction 125,742 35
36 Accumulated Deferred Investment Tax Credits 379,215 36
37 Other Deferred Credits 153,280 37
38 Other Regulatory Liabilities 1,510,443 38
39 Unamortized Gain on Reacquired Debt 4,424 39
40 Accumulated Deferred Income Taxes 5,044,951 40
41 Total Deferred Credits 7,218,055 41
42 Total Liabilities and Other Credits $27,225,655 42
</TABLE>
( ) Denotes Deduction
B-2
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
INCOME STATEMENT
TWELVE MONTHS ENDED DECEMBER 31, 1596
(000's Omitted)
<TABLE>
<CAPTION>
LINE LINE
NO. UTILITY OPERATING INCOME NO.
<S> <C> <C> <C>
Operating Revenues:
1 Electric Department $ 7,155,350 1
2 Gas Department 1,828,702 2
3 Total Operating Revenues 8,984,053 3
Operating Expenses:
4 Operation Expenses 4,895,856 4
5 Maintenance Expenses 602,399 5
6 Depreciation Expense 1,176,170 6
7 Amortization and Depletion of Utility Plant 197 7
Amortization of Property Losses, Unrecovered Plant
8 and Regulatory Study Costs 15,970 8
9 Regulatory Debit 748 9
10 Taxes Other than Income Taxes 283,624 10
11 Income Taxes Federal 628,240 11
12 Income Taxes - Other 178,393 12
13 Provision for Deterred Income Taxes (107,278) 13
14 Gains from Disposition of Allowances (18,669) 14
15 Total Utility Operating Expenses 7,655,650 15
16 Net Utility Operating Income 1,328,403 16
OTHER INCOME AND DEDUCTIONS
Other Income:
17 Nonutility Operating Income 30 17
18 Equity in Earnings of Subsidiary Companies 16,336 18
19 Interest and Dividend Income 78,975 19
20 Allowance for Other Funds Used During Construction 13,675 20
21 Miscellaneous Nonoperating Income 7,302 21
22 Gain on Disposition of Property 3,664 22
23 Total Other Income 119,982 23
Other Income Deductions:
24 Loss on Disposition of Property 795 24
25 Miscellaneous Amortization 1,993 25
26 Miscellaneous Income Deductions 227,835 26
27 Total Other Income Deductions 230,623 27
Taxes Applicable to Other Income and Deductions:
28 Taxes Other than Income Taxes 400 28
29 Income Taxes - Federal (74,228) 29
30 Income Taxes - Other (27,127) 30
31 Provision for Deferred Income Taxes (54,401) 31
32 Investment Tax Credit Adjustments - Net (17,713132
33 Total Taxes on Other Income and Deductions (173,069) 33
34 Net Other Income and Deductions 62,428 34
INTEREST CHARGES
35 Interest on Long-term Debt 504,535 35
36 Amortization of Debt Discount and Expense 7,203 36
37 Amortization of Premium on Debt 20,720 37
38 Amortization of Gain/Loss on Reacquired Debt (3) 38
39 Interest on Debt to Associated Companies 44,092 39
40 Other Interest Expense 66,586 40
41 Allowance for Borrowed Funds Used During Construction (7,511) 41
42 Net Interest Charges 635,622 42
43 Net Income $755,209 43
</TABLE>
( ) Denotes Deduction
B-3
<PAGE>
EXHIBIT C
PRESENT AND PROPOSED ELECTRIC RATES
<PAGE>
CURRENT AND PROPOSED RESIDENTIAL RATES
<TABLE>
<CAPTION>
6/10/96 6/10/96 1/1/98 1/1/98
LINE RATES RATES RATES RATES LINE
NO. SUMMER WINTER SUMMER WINTER NO.
<C> <S> <C> <C> <C> <C> <C>
1 SCHEDULE E-1 1
2 MINIMUM BILL ($/MONTH) $5.00 $5.00 $5.00 $5.00 2
3 ES UNIT DISCOUNT ($/UNIT/MONTH) $312 $3.22 $3.22 $3.22 3
4 ET UNIT DISCOUNT ($/UNIT/MONTH) $10.44 $10.44 $10.44 $10.44 4
5 ES/ET MINIMUM RATE LIMITER (s/KWH) $0.05435 $0.05435 $0.05435 $0.05435 5
6 TIER 1 ENERGY (S/KWH) $ 011589 $ 011589 $ 011589 $ 011589 6
7 TIER 2 ENERGY (S/KWH) $0.13321 $0.13321 $0.13321 $0.13321 7
8 BILL CREDIT * * 8
9 SCHEDULE EL-1(LIRA) 9
10 MINIMUM BILL ($/MONTH) $4.25 $4.25 $4.25 $4.25 10
11 TIER I ENERGY ($/KWH $0.09812 $0.09812 $0.09812 $0.09812 11
12 TIER 2 ENERGY ($/KWH) $0.11284 $0.11284 $0.11284 $0.11284 12
13 BILL CREDIT * * 13
14 SCHEDULES E-7 AND EL-7 14
15 MINIMUM BILL ($/MONTH) $5.00 $5.00 $5.00 $S.00 15
16 E-7 METER CHARGE ($/MONTH) $3.90 $3.90 $3.90 $3.90 16
17 EL-7 METER CHARGE($/MONTH) $0.00 $0.00 $0.00 $0.00 17
18 ON-PEAK ENERGY ($/KWH) $0.31524 $0.11636 $0.31524 $0.11636 18
19 OFF-PEAK ENERGY ($/KWH) $0.08515 $0.08851 $0.08515 $0.08851 19
20 BASELINE DISCOUNT ($/KWH) $0.01732 $0.01732 $0.01732 $0.01732 20
21 BILL CREDIT * * 21
22 SCHEDULE E-8 22
23 CUSTOMER CHARGE ($/MONTH) $13.92 $13.92 $13.92 $13.92 23
24 ENERGY CHARGE ($/KWH) $0.12017 $0.07308 $0.12017 $0.07308 24
25 BILL CREDIT * * 25
</TABLE>
* A 10% BILL CREDIT WILL BE APPLICABLE FOR CUSTOMERS SERVED ON THESE SCHEDULES.
C-1
<PAGE>
EXHIBIT C
ADJUSTMENT RATE TABLES
PAGE - 2
PACIFIC GAS AND ELECTRIC COMPANY
CURRENT AND PROPOSED RESIDENTIAL RATES
<TABLE>
<CAPTION>
6/10/96 6/10/96 1/1/98 1/1/98
LINE RATES RATES RATES RATES LINE
NO. SUMMER WINTER SUMMER WINTER NO.
<C> <S> <C> <C> <C> <C> <C>
1 SCHEDULE -8 (LIRA) 1
2 CUSTOMER CHARGE ($/MONTH) $11.83 $11.83 $11.83 $11.83 2
3 ENERGY CHARGE ($/KWH) $0.10176 $0.06173 $0.10176 $0.06173 3
4 BILL CREDIT 4
5 SCHEDULES E-A7 AND EL-A7 5
6 MINIMUM BILL ($/MONTH) $5.00 $5.00 $5.00 $5.00 6
7 E-A7 METER CHARGE ($/MONTH) $3.90 $3.90 $3.90 $3.90 7
8 EL-A7 METER CHARGE($/MONTH) $0.00 $0.00 $0.00 $0.00 8
9 ON-PEAK ENERGY ($/KWH) $0.34733 $0.11548 $0.34733 $0.11548 9
10 OFF-PEAK ENERGY ($/KWH) $0.08053 $0.08860 $0.08053 $0.08860 10
11 BASELINE DISCOUNT ($/KWH) $0.01732 $0.01732 $0.01732 $0.01732 11
12 BILL CREDIT * * 12
13 SCHEDULE E-9: RATE A 13
14 MINIMUM BILL ($/MONTH) $5.00 $S.00 $5.00 $5.00 14
15 E-9 METER CHARGE ($/MONTH) $7.40 $7.40 $7.40 $7.40 15
16 EL-9 METER CHARGE($/MONTH) $0.00 $0.00 $0.00 $0.00 16
17 ON-PEAK ENERGY ($/KWH) $0.30409 $0.30409 17
18 PART-PEAK ENERGY ($/KWH) $0.10439 $0.10426 $0.10439 $0.10426 18
19 OFF-PEAK ENERGY ($/KWH) $0.04405 $0.05328 $0.04405 $0.05328 19
20 BASELINE DISCOUNT ($/KWH) $0.01732 $0.01732 $0.01732 $0.01732 20
21 BILL CREDIT * * 21
22 SCHEDULE E-9: RATE B 22
23 MINIMUM BILL ($/MONTH) $5.00 $5.00 $5.00 $5.00 23
24 E-9 METER CHARGE ($/MONTH) $7.40 $7.40 $7.40 $7.40 24
25 EL-9 METER CHARGE($/MONTH) $0.00 $0.00 $0.00 $0.00 25
26 ON-PEAK ENERGY ($/KWH) $0.29963 $0.29963 26
27 PART-PEAK ENERGY ($/KWH) $0.09993 $0.10030 $0.09993 $0.10030 27
28 OFF-PEAK ENERGY ($/KWH) $0.05129 $0.05976 $0.05129 $0.05976 28
29 BASELINE DISCOUNT ($/KWH) N/A N/A N/A N/A 29
30 BILL CREDIT * * 30
</TABLE>
* A 10% BILL CREDIT WILL BE APPLICABLE FOR CUSTOMERS SERVED ON THESE SCHEDULES.
C-2
<PAGE>
EXHIBIT C
ADJUSTMENT RATE TABLES
PAGE - 3
PACIFIC GAS AND ELECTRIC COMPANY
CURRENT AND PROPOSED RESIDENTIAL RATES
<TABLE>
<CAPTION>
6/10/96 6/10/96 1/1/98 1/1/98
LINE RATES RATES RATES RATES LINE
NO. SUMMER WINTER SUMMER WINTER NO.
<C> <S> <C> <C> <C> <C> <C>
1 SCHEDULE E-9: RATE C
2 MINIMUM BILL ($/MONTH) $5.00 $5.00 $5.00 $5.00 2
3 E-9 METER CHARGE ($/MONTH) $3.90 $3.90 $3.90 $3.90 3
4 EL-9 METER CHARGE($/MONTH) $0.00 $0.00 $0.00 $0.00 4
5 ON-PEAK ENERGY ($/KWH) N/A N/A 5
6 PART-PEAK ENERGY ($/KWH) $0.18069 $0.10426 $0.18069 $0.10426 6
7 OFF-PEAK ENERGY ($/KWH) $0.04405 $0.05328 $0.04405 $0.05328 7
8 BASELINE DISCOUNT ($/KWH) $0.01732 $0.01732 $0.01732 $0.01732 8
9 BILL CREDIT * * 9
10 SCHEDULE E-9: RATE D 10
11 MINIMUM BILL ($/MONTH) $5.00 $5.00 $5.00 $5.00 11
12 E-9 METER CHARGE ($/MONTH) $3.90 $3.90 $3.90 $390 12
13 EL-9 METER CHARGE($/MONTH) $0.00 $0.00 $0.00 $000 13
14 ON-PEAK ENERGY ($/KWH) N/A N/A 14
15 PART-PEAK ENERGY ($/KWH) $0.09993 $0.10030 $0.09993 $0.10030 15
16 OFF-PEAK ENERGY ($/KWH) $0.05129 $0.05976 $0.05129 $0.05976 16
17 BASELINE DISCOUNT($/KWH) N/A N/A N/A N/A 17
18 BILL CREDIT * * 18
</TABLE>
* A 10% BILL CREDIT WILL BE APPLICABLE FOR CUSTOMERS SERVED ON THESE SCHEDULES.
C-3
<PAGE>
EXHIBIT C
ADJUSTMENT RATE TABLES
PAGE - 4
PACIFIC GAS AND ELECTRIC COMPANY
CURRENT AND PROPOSED SMALL L&P RATES
<TABLE>
<CAPTION>
6/10/96 6/10/96 1/1/98 1/1/98
LINE RATES RATES RATES RATES LINE
NO. SUMMER WINTER SUMMER WINTER NO.
<C> <S> <C> <C> <C> <C> <C>
1 SCHEDULE A-1 1
2 CUSTOMER CHARGE: SINGLE-PHASE ($/MO.) $8.10 $8.10 $8.10 $8.10 2
3 CUSTOMER CHARGE: POLYPHASE ($/MO.) $12.00 $12.00 $12.00 $12.00 3
4 ENERGY ($/KWH) $0.14870 $0.10193 $0.14870 $0.10193 4
5 BILL CREDIT * * 5
6 SCHEDULE A-6 6
7 CUSTOMER CHARGE: SINGLE-PHASE($1/MO.) $8.10 $8.10 $8.10 $8.10 7
8 METER CHARGE ($1/MONTH) $6.80 $6.80 $6.80 $6.80 8
9 CUSTOMER CHARGE: POLYPHASE ($1/MO.) $12.00 $12.00 $12.00 $12.00 9
10 ON-PEAK ENERGY ($/KWH) $0.23258 $0.23258 10
11 PART-PEAK ENERGY ($/KWH) $0.10288 $0.11562 $0.10288 $0.11562 11
12 OFF-PEAK ENERGY ($/KWH) $0.05618 $0.07169 $0.05618 $0.07169 12
13 BILL CREDIT * * 13
14 SCHEDULE A-15 14
15 CUSTOMER CHARGE ($1/MONTH) $8.10 $8.10 $8.10 $8.10 15
16 FACILITY CHARGE ($1/MONTH) $7.80 $7.80 $7.80 $7.80 16
17 ENERGY ($/KWH) $0.17985 $0.14452 $0.17985 $0.14452 17
18 SCHEDULE C-1 18
19 CUSTOMER CHARGE ($1/MONTH) $8.10 $8.10 $8.10 $8.10 19
20 ENERGY ($/KWH) $0.10131 $0.10131 $0.10131 $0.10131 20
</TABLE>
* A 10% BILL CREDIT WILL BE APPLICABLE FOR CUSTOMERS SERVED ON THESE SCHEDULES.
C-4
<PAGE>
EXHIBIT C
ADJUSTMENT RATE TABLES
PAGE - 5
PACIFIC GAS AND ELECTRIC COMPANY
CURRENT AND PROPOSED MEDIUM L&P RATES
<TABLE>
<CAPTION>
6/10/96 6/10/96 1/1/98 1/1/98
LINE RATES RATES RATES RATES LINE
NO. SUMMER WINTER SUMMER WINTER NO.
<C> <S> <C> <C> <C> <C> <C>
1 SCHEDULE A-10 1
2 CUSTOMER CHARGE ($/MONTH) $75.00 $75.00 $75.00 $75.00 2
3 MAXIMUM DEMAND CHARGE ($/KW/MO) 3
4 SECONDARY VOLTAGE ($/KW/MO) $6.70 $1.65 $6.70 $1.65 4
5 PRIMARY VOLTAGE ($/KW/MO) $5.50 $1.65 $5.50 $1.65 5
6 TRANSMISSION VOLTAGE ($/KW/MO) $1.95 $0.45 $1.95 $0.45 6
7 ENERGY CHARGE($/KWH) $0.08915 $0.07279 $0.08915 $0.07279 7
8 PRIMARY VOLTAGE DISCOUNT ($/KW/MO) $1.20 $0.00 $1.20 $0.00 8
9 TRANSMISSION DISCOUNT ($/KW/MO) $4.75 $1.20 $4.75 $1.20 9
10 BILL CREDIT * * 10
</TABLE>
* A 10% BILL CREDIT WILL BE APPLICABLE FOR CUSTOMERS ON THIS SCHEDULE WHOSE
MAXIMUM BILLING DEMAND IS LESS THAN 20 kW FOR AT LEAST NINE CONSECUTIVE BILLING
PERIODS DURING THE MOST RECENT 12-MONTH PERIOD. ELIGIBILITY WILL BE DETERMINED
ON A ONE-TIME BASIS.
C-5
<PAGE>
EXHIBIT C
ADJUSTMENT RATE TABLES
PAGE - 6
PACIFIC GAS AND ELECTRIC COMPANY
CURRENT AND PROPOSED E-19 FIRM RATES
<TABLE>
<CAPTION>
6/10/96 6/10/96 1/1/98 1/1/98
LINE RATES RATES RATES RATES LINE
NO. SUMMER WINTER SUMMER WINTER NO.
<C> <S> <C> <C> <C> <C> <C>
1 SCHEDULE-l9 T FIRM 1
2 CUSTOMER CHARGE GREATER THAN 500 KW ($/MONTH) $ 61000 $ 61000 $ 610.00 $ 610.00 2
3 CUSTOMER CHARGE LESS THAN 500 KW ($/MONTH) $ 7500 $ 75.00 $ 75.00 $ 75.00 3
4 TOU METER CHARGE LESS THAN 500 KW $ 600 $ 600 $ 6.00 $ 6.00 4
5 ON-PEAK DEMAND CHARGE ($/KW/MONTH) $ 7.50 $ 7.50 5
6 PARTIAL PEAK DEMAND CHARGE ($/KW/MO) $ 0.60 $ 0.75 $ 0.60 $ 0.75 6
7 MAXIMUM DEMAND CHARGE ($/KW/MONTH) $ 0.35 $ 0.35 $ 0.35 $ 0.35 7
8 ON-PEAK ENERGY ($/KWH) $ 0.08676 $ 0.08676 8
9 PARTIAL-PEAK ENERGY ($/KWH) $ 0.06580 $ 0.08114 $ 0.06580 $ 0.08114 9
10 OFF-PEAK ENERGY ($/KWH) $ 006180 $ 0.06679 $ 0.06180 $ 0.06679 10
11 ON-PEAK RATE LIMIT ($/KWH) $ 0.58676 $ 0.58676 11
12 BILL CREDIT * * 12
13 SCHEDULE E-l9 P FIRM 13
14 CUSTOMER CHARGE GREATER THAN 500 KW ($/MONTH) $ 140.00 $ 140.00 $ 140.00 $ 140.00 14
15 CUSTOMER CHARGE LESS THAN 500 KW ($/MONTH) $ 75.00 $ 75.00 $ 75.00 $ 75.00 15
16 TOU METER CHARGE LESS THAN 500 KW $ 6.00 $ 6.00 $ 6.00 $ 6.00 16
17 ON-PEAK DEMAND CHARGE ($/KW/MONTH) $ 11.80 $ 11.80 17
18 PARTIAL PEAK DEMAND CHARGE ($/KW/MO) $ 2.65 $ 2.65 $ 2.65 $ 2.65 18
19 MAXIMUM DEMAND CHARGE ($/KW/MONTH) $ 2.55 $ 2.55 $ 2.55 $ 2.55 19
20 ON-PEAK ENERGY ($/KWH) $ 0.06271 $ 0.06271 20
21 PARTIAL-PEAK ENERGY ($/KWH) $ 0.04868 $ 0.05700 $ 0.04868 $ 0.05700 21
22 OFF-PEAK ENERGY ($/KWH) $ 0.04683 $ 0.04782 $ 0.04683 $ 0.04782 22
23 AVERAGE RATE LIMIT ($/KWH) $ 0.14043 $ 0.14043 23
24 ON-PEAK RATE LIMIT ($/KWH) $ 0.84937 $ 0.84937 24
25 BILL CREDIT * * 25
</TABLE>
* A 10% BILL CREDIT WILL BE APPLICABLE FOR CUSTOMERS ON THIS SCHEDULE WHOSE
MAXIMUM BILLING DEMAND IS LESS THAN 20 kW FOR AT LEAST NINE CONSECUTIVE BILLING
PERIODS DURING THE MOST RECENT 12-MONTH PERIOD. ELIGIBILITY WILL BE DETERMINED
ON A ONE-TIME BASIS.
C-6
<PAGE>
EXHIBIT C
ADJUSTMENT RATE TABLES
PAGE - 7
PACIFIC GAS AND ELECTRIC COMPANY
CURRENT AND PROPOSED E-19 FIRM RATES
<TABLE>
<CAPTION>
6/10/96 6/10/96 1/1/98 1/1/98
LINE RATES RATES RATES RATES LINE
NO. SUMMER WINTER SUMMER WINTER NO.
<C> <S> <C> <C> <C> <C> <C>
1 SCHEDULE E-19 S FIRM 1
2 CUSTOMER CHARGE GREATER THAN 500 KW ($/MONTH) $ 175.00 $ 175.00 $ 175.00 $ 175.00 2
3 CUSTOMER CHARGE LESS THAN 500 KW ($/MONTH) $ 75.00 $ 75.00 $ 75.00 $ 75.00 3
4 TOU METER CHARGE LESS THAN 500 KW $ 6.00 $ 6.00 $ 6.00 $ 6.00 4
5 ON-PEAK DEMAND CHARGE ($/KW/MONTH) $ 13.35 $ 13.35 5
6 PARTIAL PEAK DEMAND CHARGE ($/KW/MO) $ 3.70 $ 3.65 $ 3.70 $ 3.65 6
7 MAXIMUM DEMAND CHARGE ($/KW/MONTH) $ 2.55 $ 2.55 $ 2.55 $ 2.55 7
8 ON-PEAK ENERGY ($/KWH) $ 0.08773 $ 0.08773 8
9 PARTIAL-PEAK ENERGY ($/KWH) $ 0.05810 $0.06392 $ 0.05810 $0.06392 9
10 OFF-PEAK ENERGY ($/KWH) $ 0.05059 $0.05038 $ 0.05059 $0.05038 10
11 AVERAGE RATE LIMIT ($/KWH) $ 0.14043 $ 0.14043 11
12 ON-PEAK RATE LIMIT ($/KWH) $ 0.97773 $ 0.97773 12
13 BILL CREDIT * * 13
</TABLE>
C-7
<PAGE>
EXHIBIT C
ADJUSTMENT RATE TABLES
PAGE - 8
PACIFIC GAS AND ELECTRIC COMPANY
CURRENT AND PROPOSED E-19 NONFIRM RATES
<TABLE>
<CAPTION>
6/10/96 6/10/96 1/1/98 1/1/98
LINE RATES RATES RATES RATES LINE
NO. SUMMER WINTER SUMMER WINTER NO.
<C> <S> <C> <C> <C> <C> <C>
1 SCHEDULE E-19 T NONFIRM 1
2 CUSTOMER CHARGE($/MONTH) $ 610.00 $ 610.00 $ 61000 $ 61000 2
3 CURTAILABLE METER CHARGE($/MONTH) $ 190.00 $ 190.00 $ 19000 $ 190.00 3
4 INTERRUPTIBLE METER CHARGE($/MONTH) $ 200.00 $ 200.00 $ 20000 $ 2.0000 4
5 ON-PEAK DEMAND CHARGE($KW/MONTH) $ 0.00 $ 0.00 5
6 PARTIAL PEAK DEMAND CHARGE ($/KW/MO) $ 0.10 $ 0.25 $ 0.10 $ 0.25 6
7 MAXIMUM DEMAND CHARGE ($KW/MONTH) $ 0.35 $ 0.35 $ 0.35 $ 0.35 7
8 ON-PEAK ENERGY ($KWH) $ 0.07429 $ 0.07429 8
9 PARTIAL-PEAK ENERGY ($KWH) $ 0.06448 $ 0.07982 $ 0.06448 $ 0.07982 9
10 OFF-PEAK ENERGY ($KWH) $ 0.06048 $ 0.06547 $ 0.06048 $ 0.06547 10
11 UFR CREDIT ($KWH) $ 0.00091 $ 0.00091 $ 0.00091 $ 0.00091 11
12 NONCOMPLIANCE PENALTY ($KWH/EVENT) $ 8.401$420 $8.4()/$4.20 $8.401$4.20 $8.40/$4.20 12
13 SCHEDULE E-19 P NONFIRM 13
14 CUSTOMER CHARGE ($/MONTH) $ 140.00 $ 140.00 $ 140.00 $ 140.00 14
15 CURTAILABLE METER CHARGE ($/MONTH) $ 190.00 $ 190.00 $ 190.00 $ 190.00 15
16 INTERRUPTIBLE METER CHARGE ($/MONTH) $ 200.00 $ 200.00 $ 200.00 $ 200.00 16
17 ON-PEAK DEMAND CHARGE ($/KW/MONTH) $ 4.30 $ 4.30 17
18 PARTIAL PEAK DEMAND CHARGE($/KW/MO) $ 2.15 $ 2.15 $ 2.15 $ 2.15 18
19 MAXIMUM DEMAND CHARGE ($/KW/MONTH) $ 2.55 $ 2.55 $ 2.55 $ 2.55 19
20 ON-PEAK ENERGY ($/KWH) $ 0.05024 $ 0.05024 20
21 PARTIAL-PEAK ENERGY ($/KWH) $ 0.04736 $ 0.05568 $ 0.04736 $ 0.05568 21
22 OFF-PEAK ENERGY ($/KWH) $ 0.04551 $ 0.04650 $ 0.04551 $ 0.04650 22
23 UFR CREDIT ($/KWH) $ 0.00091 $ 0.00091 $ 0.00091 $ 0.00091 23
24 NONCOMPLIANCE PENALTY ($/KWH/EVENT) $8.40/$4.20 $ 8.40/$4.20 $8.40/$4.20 $8.40/$4.20 24
25 SCHEDULE E-19 S NONFIRM 25
26 CUSTOMER CHARGE($/MONTH) $ 175.00 $ 175.00 $ 175.00 $ 175.00 26
27 CURTAILABLE METER CHARGE($/MONTH) $ 190.00 $ 190.00 $ 190.00 $ 190.00 27
28 INTERRUPTIBLE METER CHARGE($/MONTH) $ 200.00 $ 200.00 $ 200.00 $ 200.00 28
29 ON-PEAK DEMAND CHARGE ($/KW/MONTH) $ 5.85 $ 5.85 29
30 PARTIAL PEAK DEMAND CHARGE ($/KW/MO) $ 3.20 $ 3.15 $ 3.20 $ 3.15 30
31 MAXIMUM DEMAND CHARGE ($/KW/MONTH) $ 2.55 $ 2.55 $ 2.55 $ 2.55 31
32 ON-PEAK ENERGY ($/KWH) $ 0.07526 $ 0.07526 32
33 PARTIAL-PEAK ENERGY ($/KWH) $ 0.05678 $ 0.06260 $ 0.05678 $ 0.06260 33
34 OFF-PEAK ENERGY ($/KWH) $ 0.04927 $ 0.04906 $ 0.04927 $ 0.04906 34
35 UFR CREDIT ($/KWH) $ 0.00091 $ 0.00091 $ 0.00091 $ 0.00091 35
36 NONCOMPLIANCE PENALTY ($/KWH/EVENT) $8.40/$4.20 $ 8.40/$4.20 $8.40/$4.20 $8.40/$4.20 36
</TABLE>
C-8
<PAGE>
EXHIBIT C
ADJUSTMENT RATE TABLES
PAGE - 9
PACIFIC GAS AND ELECTRIC COMPANY
CURRENT AND PROPOSED E-20 FIRM RATES
<TABLE>
<CAPTION>
6/10/96 6/10/96 1/1/98 1/1/98
LINE RATES RATES RATES RATES LINE
NO. SUMMER WINTER SUMMER WINTER NO.
<C> <S> <C> <C> <C> <C> <C>
1 SCHEDULE E-20 T 1
2 CUSTOMER CHARGE ($/MONTH)-FIRM $ 715.00 $ 715.00 $ 715.00 $ 715.00 2
3 ON-.PEAK DEMAND CHARGE ($/KW/MONTH) $ 7.50 $ 7.50 3
4 PARTIAL PEAK DEMAND CHARGE ($/KW/MO) $ 0.60 $ 0.75 $ 060 $ 0.75 4
5 MAXIMUM DEMAND CHARGE ($/KW/MONTH) $ 0.35 $ 0.35 $ 0.35 $ 0.35 5
6 ON-PEAK ENERGY ($/KWH) $ 0.05750 $0.05750 6
7 PARTIAL-PEAK ENERGY ($/KWH) $ 0.04361 $ 0.05369 $0.04361 $0.05369 7
8 OFF-PEAK ENERGY ($/KWH) $ 0.04097 $ 0.04420 $0.04097 $0.04420 8
9 ON-PEAK RATE LIMIT ($/KWH) $ 0.55750 $0.55750 9
10 ECONOMIC STIMULUS RATE CREDIT ($/KWH) $ 0.00432 $ 0.00432 $0.00432 $0.00432 10
11 SCHEDULE E-20 P FIRM 11
12 CUSTOMER CHARGE($/MONTH) $ 310.00 $ 310.00 $ 310.00 $ 310.00 12
13 ON-PEAK DEMAND CHARGE($/KW/MONTH) $ 11.80 $ 11.80 13
14 PARTIAL PEAK DEMAND CHARGE ($/KW/MO) $ 2.65 $ 2.65 $ 2.65 $ 2.65 14
15 MAXIMUM DEMAND CHARGE ($/KW/MONTH) $ 2.55 $ 2.55 $ 2.55 $ 2.55 15
16 ON-PEAK ENERGY ($/KWH) $ 0.06210 $0.06210 16
17 PARTIAL-PEAK ENERGY ($/KWH) $ 0.04821 $ 0.05624 $0.04821 $0.05624 17
18 OFF-PEAK ENERGY ($/KWH) $ 0.04637 $ 0.04719 $0.04637 $0.04719 18
19 AVERAGE RATE LIMIT ($/KWH) $ 0.13995 $0.13995 19
20 ON-PEAK RATE LIMIT ($/KWH) $ 0.84876 $0.84876 20
21 ECONOMIC STIMULUS RATE CREDIT ($/KWH) $ 0.00432 $ 0.00432 $0.00432 $0.00432 21
22 SCHEDULE E-20 S FIRM 22
23 CUSTOMER CHARGE ($/MONTH) $ 385.00 $ 385.00 $ 385.00 $ 385.00 23
24 ON-PEAK DEMAND CHARGE ($/KW/MONTH) $ 13.35 $ 13.35 24
25 PARTIAL PEAK DEMAND CHARGE ($/KW/MO) $ 3.70 $ 3.65 $ 3.70 $ 3.65 25
26 MAXIMUM DEMAND CHARGE ($/KW/MONTH) $ 2.55 $ 2.55 $ 2.55 $ 2.55 26
27 ON-PEAK ENERGY ($/KWH) $ 0.08708 $0.08708 27
28 PARTIAL-PEAK ENERGY ($/KHW) $ 0.05767 $ 0.06344 $0.05767 $0.06344 28
29 OFF-PEAK ENERGY ($/KWH) $ 0.05022 $0.05~001 $0.05022 $0.05001 29
30 AVERAGE RATE LIMIT ($/KWH) $ 0.13995 $0.13995 30
31 ON-PEAK RATE LIMIT ($/KWH) $ 0.97708 $0.97708 31
32 ECONOMIC STIMULUS RATE CREDIT ($/KWH) $ 0.00432 $ 0.00432 $0.00432 $0.00432 32
</TABLE>
C-9
<PAGE>
EXHIBIT C
ADJUSTMENT RATE TABLES
PAGE - 10
PACIFIC GAS AND ELECTRIC COMPANY
CURRENT AND PROPOSED E-20 NONFIRM RATES
<TABLE>
<CAPTION>
6/10/96 6/10/96 1/1/98 1/1/98
LINE RATES RATES RATES RATES LINE
NO. SUMMER WINTER SUMMER WINTER NO.
<C> <S> <C> <C> <C> <C> <C>
1 SCHEDULE E-20 T NONFIRM 1
2 CUSTOMER CHARGE($/MONTH) $ 715.00 $ 715.00 $ 715.00 $ 715.00 2
3 CURTAILABLE METER CHARGE($/MONTH) $ 190.00 $ 190.00 $ 190.00 $ 190.00 3
4 INTERRUPTIBLE METER CHARGE ($/MONTH) $ 200.00 $ 200.00 $ 200.00 $ 200.00 4
5 ON-PEAK DEMAND CHARGE ($/KW/MONTH) $ 0.00 $ 0.00 5
6 PARTIAL PEAK DEMAND CHARGE ($/KW/MO) $ 0.10 $ 0.25 $ 0.10 $ 0.25 6
7 MAXIMUM DEMAND CHARGE ($/KW/MONTH) $ 0.35 $ 0.35 $ 0.35 $ 0.35 7
8 ON-PEAK ENERGY ($/KWH) $ 0.04503 $ 0.04503 8
9 PARTIAL-PEAK ENERGY ($/KWH) $ 0.04229 $ 0.05237 $ 0.04229 $ 0.05237 9
10 OFF-PEAK ENERGY ($/KWH) $ 0.035%5 $ 0.04288 $ 0.03965* $ 0.04288 10
11 UFR CREDIT ($/KWH) $ 0.00091 $ 0.00091 $ 0.00091 $ 0.00091 11
12 NONCOMPLIANCE PENALTY ($/KWH/EVENT) $8.40/$4.20 $8.40/$4.20 $8.40/$4.20 $8.40/$4.20 12
13 ECONOMIC STIMULUS RATE CREDIT ($/KWH) $ 0.00432 $ 0.00432 $ 0.00432 $ 0.00432 13
14 SCHEDULE E-20 P NONFIRM 14
15 CUSTOMER CHARGE ($/MONTH) $ 310.00 $ 310.00 $ 310.00 $ 310.00 15
16 CURTAILABLE METER CHARGE($/MONTH) $ 190.00 $ 190.00 $ 190.00 $ 190.00 16
17 INTERRUPTIBLE METER CHARGE($/MONTH) $ 200.00 $ 200.00 $ 200.00 $ 200.00 17
18 ON-PEAK DEMAND CHARGE($/KW/MONTH) $ 4.30 $ 4.30 18
19 PARTIAL PEAK DEMAND CHARGE($/KW/MO) $ 2.15 $ 2.15 $ 2.15 $ 2.15 19
20 MAXIMUM DEMAND CHARGE ($/KW/MONTH) $ 2.55 $ 2.55 $ 2.55 $ 2.55 20
21 ON-PEAK ENERGY ($/KWH) $ 0.04963 $ 0.04963 21
22 PARTIAL-PEAK ENERGY ($/KWH) $ 0.04689 $ 0.05492 $ 0.04689 $ 0.05492 22
23 OFF-PEAK ENERGY ($/KWH) $ 0.04505 $ 0.04587 $ 0.04505 $ 0.04587 23
24 UFR CREDIT ($/KWH) $ 0.00091 $ 0.00091 $ 0.00091 $ 0.00091 24
25 NONCOMPLIANCE PENALTY ($/KWH/EVENT) $8.40/$4.20 $8.40/$4.20 $8.40/$4.20 $8.40/$4.20 25
26 ECONOMIC STIMULUS RATE CREDIT ($/KWH) $ 0.00432 $ 0.00432 $ 0.00432 $ 0.00432 26
27 SCHEDULE E-20 S NONFIRM 27
28 CUSTOMER CHARGE ($/MONTH) $ 38S.00 $ 385.00 $ 385.00 $ 385.00 28
29 CURTAILABLE METER CHARGE($/MONTH) $ 190.00 $ 190.00 $ 190.00 $ 190.00 29
30 INTERRUPTIBLE METER CHARGE ($/MONTH) $ 200.00 $ 200.00 $ 200.00 $ 200.00 30
31 ON-PEAK DEMAND CHARGE ($/KW/MONTH) $ 5.85 $ 5.85 31
32 PARTIAL PEAK DEMAND CHARGE ($/KW/MO) $ 3.20 $ 3.15 $ 3.20 $ 3.15 32
33 MAXIMUM DEMAND CHARGE ($/KW/MONTH) $ 2.55 $ 2.55 $ 2.55 $ 2.55 33
34 ON-PEAK ENERGY ($/KWH) $ 0.07461 $ 0.07461 34
35 PARTIAL-PEAK ENERGY ($/KWH) $ 0.05635 $ 0.06212 $ 0.05635 $ 0.06212 35
36 OFF-PEAK ENERGY ($/KWH) $ 0.04890 $ 0.04869 $ 0.04890 $ 0.04869 36
37 UFR CREDIT ($/KWH) $ 0.00091 $ 0.00091 $ 0.00091 $ 0.00091 37
38 NONCOMPLIANCE PENALTY ($/KWH/EVENT) $8.40/$4.20 $8.40/$4.20 $8.40/$4.20 $8.40/$4.20 38
39 ECONOMIC STIMULUS RATE CREDIT ($/KWH) $ 0.00432 $ 000432 $ 0.00432 $ 000432 39
</TABLE>
C-10
<PAGE>
EXHIBIT C
ADJUSTMENT RATE TABLES
PAGE - 11
PACIFIC GAS AND ELECTRIC COMPANY
CURRENT AND PROPOSED REAL TIME PRICING RATES
<TABLE>
<CAPTION>
6/10/96 6/10/96 1/1/98 1/1/98
LINE RATES RATES RATES RATES LINE
NO. SUMMER WINTER SUMMER WINTER NO.
<C> <S> <C> <C> <C> <C> <C>
1 SCHEDULE A-RTP TRANSMISSION 1
2 E-2O CUSTOMER CHARGE($/MONTH) $ 715.00 $ 715.00 $ 715.00 $ 715.00 2
3 OPTIONAL SERVICE CHARGE($/MONTH) $ 275.00 $ 275.00 $ 275.00 $ 275.00 3
4 MAXIMUM DEMAND CHARGE($/KW/MONTH) $ 0.35 $ 0.35 $ 0.35 $ 0.35 4
5 BASE ENERGY RATE ($/KWH) $ 0.00346 $0.00346 $0.00346 $0.00346 5
6 ECONOMIC STIMULUS RATE CREDIT ($/KWH) $ 0.00432 $0.00432 $0.00432 $0.00432 6
7 ON-PEAK ENERGY MULTIPLIER 1.9803 1.9803 7
8 PART-PEAK ENERGY MULTIPLIER 1.9803 2.0185 1.9803 2.0185 8
9 OFF-PEAK ENERGY MULTIPLIER 1.9803 2.0185 1.9803 2.0185 9
10 LOAD MAN. PRICE SIGNAL ($/KW-DAY) (10 DAYS) $ 3.84593 $3.84593 10
11 TEMP. THRESH. T&D ADDER ($/KW-DAY)(25 DAYS) $ 2.08015 $0.29551 $2.08015 $0.29551 11
12 DAILY TRANS. AND DIST. ADDER(APP $/KW-DAY) $ 0.41603 $0.05910 $0.41603 $0.05910 12
13 SCHEDULE A-RTP SECONDARY
14 E-l9 CUSTOMER CHARGE($/MONTH) $ 175.00 $ 175.00 $ 175.00 $ 175.00 14
15 E-20 CUSTOMER CHARGE($/MONTH) $ 385.00 $ 385.00 $ 385.00 $ 385.00 15
16 OPTIONAL SERVICE CHARGE($/MONTH) $ 275.00 $ 275.00 $ 275.00 $ 275.00 16
17 MAXIMUM DEMAND CHARGE($/KW/MONTH) $ 2.55 $ 2.55 $ 2.55 $ 2.55 17
18 BASE ENERGY RATE ($/KWH) $ 0.00346 $0.00346 $0.00346 $0.00346 18
19 ECONOMIC STIMULUS RATE CREDIT ($/KWH) $ 0.00432 $0.00432 $0.00432 $ 000432 19
20 ON-PEAK ENERGY MULTIPLIER 1.9803 1.9803 20
21 PART-PEAK ENERGY MULTIPLIER 1.9803 2.0185 1.9803 2 0185 21
22 OFF-PEAK ENERGY MULTIPLIER 1.9803 2.0185 1.9803 2.0185 22
23 LOAD MAN. PRICE SIGNAL($/KW-DAY) (10 DAYS) $ 3.84593 $3.84593 23
24 TEMP. THRESH. T&D ADDER ($/KW-DAY)(42 DAYS) $ 2.08015 $0.29551 $2.08015 $0.29551 24
25 DAILY TRANS. AND DIST. ADDER (APP $/KW-DAY) $ 0.41603 $0.05910 $0.41603 $0.05910 25
</TABLE>
C-11
<PAGE>
EXHIBIT C
ADJUSTMENT RATE TABLES
PAGE - 12
PACIFIC GAS AND ELECTRIC COMPANY
CURRENT AND PROPOSED LARGE L&P RATES
E-25
<TABLE>
<CAPTION>
6/10/96 6/10/96 1/1/98 1/1/98
LINE RATES RATES RATES RATES LINE
NO. SUMMER WINTER SUMMER WINTER NO.
<C> <S> <C> <C> <C> <C> <C>
1 SCHEDULE E-25T
2 CUSTOMER CHARGE ($/MONTH) $ 610.00 $ 610.00 $ 610.00 $ 610.00 2
3 ON-PEAK DEMAND CHARGE ($/KW/MONTH) $ 7.50 $ 7.50 3
4 PARTIAL PEAK DEMAND CHARGE ($/KW/MO) $ 0.60 $ 0.75 $ 0.60 $ 0.75 4
5 MAXIMUM DEMAND CHARGE($/KW/MONTH) $ 0.35 $ 0.35 $ 0.35 $ 0.35 5
6 ON-PEAK ENERGY ($/KWH) $ 0.09724 $ 0.09724 6
7 PART-PEAK ENERGY ($/KWH) $ 0.06580 $ 0.08114 $ 0.06580 $ 0.08114 7
8 OFF-PEAK ENERGY ($/KWH) $ 0.06180 $ 0.06679 $ 0.06180 $ 0.06679 8
9 ON-PEAK RATE LIMIT ($/KWH) $ 0.58676 $ 0.58676 9
10 SCHEDULE E-25P 10
11 CUSTOMER CHARGE ($/MONTH) $ 140.00 $ 140.00 $ 140.00 $ 140.00 11
12 ON-PEAK DEMAND CHARGE ($/KW/MONTH) $ 11.80 $ 11.80 12
13 PARTIAL PEAK DEMAND CHARGE ($/KW/MO) $ 2.65 $ 2.65 $ 2.65 $ 2.65 13
14 MAXIMUM DEMAND CHARGE ($/KW/MONTH) $ 2.55 $ 2.55 $ 2.55 $ 2.55 14
15 ON-PEAK ENERGY ($/KWH) $ 0.06972 $ 0.06972 15
16 PART-PEAK ENERGY ($/KWH) $ 0.04868 $ 0.05700 $ 0.04868 $ 0.05700 16
17 OFF-PEAK ENERGY ($/KWH) $ 0.04683 $ 0.04782 $ 0.04683 $ 0.04782 17
18 AVERAGE RATE LIMIT ($/KWH) $ 0.14043 $ 0.14043 18
19 ON-PEAK RATE LIMIT ($/KWH) $ 0.84937 $ 0.84937 19
20 SCHEDULE E-25S 20
21 CUSTOMER CHARGE ($/MONTH) $ 175.00 $ 175.00 $ 175.00 $ 175.00 21
22 ON-PEAK DEMAND CHARGE ($/KW/MONTH) $ 13.35 $ 13.35 22
23 PARTIAL PEAK DEMAND CHARGE ($/KW/MO) $ 3.70 $ 3.65 $ 3.70 $ 3.65 23
24 MAXIMUM DEMAND CHARGE ($/KW/MONTH) $ 2.55 $ 2.55 $ 2.55 $ 2.55 24
25 ON-PEAK ENERGY ($/KWH) $ 0.10255 $ 0.10255 25
26 PART-PEAK ENERGY ($/KWH) $ 0.05810 $ 0.06392 $ 0.05810 $ 0.06392 26
27 OFF-PEAK ENERGY ($/KWH) $ 0.05059 $ 0.05038 $ 0.05059 $ 0.05038 27
28 AVERAGE RATE LIMIT ($/KWH) $ 0.14043 $ 0.14043 28
29 ON-PEAK RATE LIMIT ($/KWH) $ 0.97773 $ 0.97773 29
</TABLE>
C-12
<PAGE>
EXHIBIT C
ADJUSTMENT RATE TABLES
PAGE - 13
PACIFIC GAS AND ELECTRIC COMPANY
CURRENT AND PROPOSED STANDBY RATES
<TABLE>
<CAPTION>
6/10/96 6/10/96 1/1/98 1/1/98
LINE RATES RATES RATES RATES LINE
NO. SUMMER WINTER SUMMER WINTER NO.
<C> <S> <C> <C> <C> <C> <C>
1 SCHEDULE S - TRANSMISSION 1
2 CONTRACT CAPACITY CHARGE ($/KW/MO.) $ 0.35 $ 0.35 $ 0.35 $ 0.35 2
3 EFFECTIVE RESERVATION CHARGE ($/KW/MO.) $ 0.30 $ 0.30 $ 0.30 $ 0.30 3
4 ON-PEAK ENERGY ($/KWH) $ 030168 $ 030168 4
5 PART-PEAK ENERGY ($/KWH) $ 0.05954 $0.07136 $0.05954 $0.07136 5
6 OFF-PEAK ENERGY ($/KWH) $ 0.04014 $0.04994 $0.04014 $0.04994 6
7 SCHEDULE S - PRIMARY 7
8 CONTRACT CAPACITY CHARGE ($/KW/MO.) $ 2.55 $ 2.55 $ 2.55 $ 2.55 8
9 EFFECTIVE RESERVATION CHARGE ($/KW/MO.) $ 2.17 $ 2.17 $ 2.17 $ 2.17 9
10 ON-PEAK ENERGY($/KWH) $ 0.36632 $0.36632 10
11 PART-PEAK ENERGY ($/KWH) $ 0.10814 $0.09473 $0.10814 $0.09473 11
12 OFF-PEAK ENERGY ($/KWH) $ 0.03912 $0.04996 $0.03912 $0.04996 12
13 SCHEDULES - SECONDARY 13
14 CONTRACT CAPACITY CHARGE ($/KW/MO.) $ 2.55 $ 2.55 $ 2.55 $ 2.55 14
15 EFFECTIVE RESERVATION CHARGE ($/KW/MO.) $ 2.17 $ 2.17 $ 2.17 $ 2.17 15
16 ON-PEAK ENERGY ($/KWH) $ 0.39159 $0.39159 16
17 PART-PEAK/ENERGY($/KWH) $ 0.11648 $0.10291 $0.11648 $0.10291 17
18 OFF-PEAK ENERGY ($/KWH) $ 0.04296 $0.05489 $0.04296 $0.05489 18
19 SCHEDULES - NONFIRM 19
20 UFR CREDIT $ 0.00091 $0.00091 $0.00091 $0.00091 20
21 TOU ENERGY NONFIRM CREDIT 21
22 ON-PEAK ENERGY ($/KWH) $ 0.01873 $0.01873 22
23 PART-PEAK ENERGY ($/KWH) $ 0.00187 $0.00187 $0.00187 $0.00187 23
</TABLE>
C-13
<PAGE>
EXHIBIT C
ADJUSTMENT RATE TABLES
PAGE 14
PACIFIC GAS AND ELECTRIC COMPANY
CURRENT AND PROPOSED STANDBY RATES
<TABLE>
<CAPTION>
6/10/96 RATES 6/10/96 RATES 1/1/98 RATES 1/1/98 RATES
LINE NO. SUMMER WINTER SUMMER WINTER LINE NO.
<C> <S> <C> <C> <C> <C> <C>
1 SCHEDULE S CUSTOMER AND 1
METER CHARGES
2 RESIDENTIAL 2
3 MINIMUM BILL ($/MO) $ 5.00 $ 5.00 $ 5.00 $ 5.00 3
4 TOU METER CHARGE ($/MO) $ 3.90 $ 3.90 $ 3.90 $ 3.90 4
5 AGRICULTURAL 5
6 CUSTOMER CHARGE ($/MO) $ 16.00 $ 16.00 $ 1600 $ 16.00 6
7 TOU METER CHARGE ($/MO) $ 6.00 $ 6.00 $ 6.00 $ 6.00 7
8 SMALL LIGHT AND POWER (less 8
than or equal to 50 kW)
9 SINGLE PHASE CUSTOMER $ 8.10 $ 8.10 $ 8 10 $ 8.10 9
CHARGE($/MO)
10 POLY PHASE CUSTOMER CHARGE $ 12.00 $ 12.00 $ 12.00 $ 12.00 10
($/MO)
11 METER CHARGE ($/MO) $ 6.80 $ 6.80 $ 6.80 $ 6.80 11
12 MEDIUM LIGHT AND POWER 12
(greater than 50kW,
less than 500kW)
13 CUSTOMER CHARGE ($/MO) $ 75.00 $ 75.00 $ 75.00 $ 75.00 13
14 METER CHARGE ($/MO) $ 6.00 $ 6.00 $ 6.00 $ 6.00 14
15 MEDIUM LIGHT AND POWER 15
(greater than 500kW)
16 TRANSMISSION CUSTOMER CHARGE $610.00 $610.00 $610.00 $610.00 16
($/MO)
17 PRIMARY CUSTOMER CHARGE($/MO) $140.00 $140.00 $140.00 $ 14000 17
18 SECONDARY CUSTOMER CHARGE $175.00 $175.00 $175.00 $175.00 18
($/MO)
19 LARGE LIGHT AND POWER 19
(greater than 1000kW)
20 TRANSMISSION CUSTOMER CHARGE $715.00 $715.00 $715.00 $715.00 20
($/MO)
21 PRIMARY CUSTOMER CHARGE($/MO) $310.00 $310.00 $310.00 $310.00 21
22 SECONDARY CUSTOMER CHARGE $385.00 $385.00 $385.00 $385.00 22
($/MO)
23 NONFIRM METER CHARGES 23
24 CURTAILABLE METER CHARGE $190.00 $190.00 $190.00 $190.00 24
($/MO)
25 INTERRUPTIBLE METER CHARGES $200.00 $200.00 $200.00 $200.00 25
($/MO)
26 REDUCED CUSTOMER CHARGES 26
($/MO)
27 A-6 $ 660 $ 6.60 $ 6.60 $ 6.60 27
28 E19 V $ 56.60 $ 56.60 $ 56.60 $ 56.60 28
29 E-19 PRIMARY and SECONDARY $ 56.60 $ 56.60 $ 56.60 $ 56.60 29
</TABLE>
C-14
<PAGE>
EXHIBIT C
ADJUSTMENT RATE TABLES
PAGE 15
PACIFIC GAS AND ELECTRIC COMPANY
CURRENT AND PROPOSED AGRICULTURAL RATES
<TABLE>
<CAPTION>
LINE 6/10/96 RATES 6/10/96 RATES 1/1/98 RATES 1/1/98 RATES
NO. SUMMER WINTER SUMMER WINTER LINE NO.
<C> <S> <C> <C> <C> <C> <C>
1 SCHEDULE AG-1A 1
2 CUSTOMER CHARGE ($/MONTH) $ 12.00 $ 12.00 $ 12.00 $ 12.00 2
3 CONNECTED LOAD CHARGE $ 2.40 $ 2.20 $ 2.40 $ 2.20 3
($/KW/MONTH)
4 ENERGY CHARGE ($/KWH) $0.13548 $0.l3548 $0.13548 $0.13548 4
5 SCHEDULE AG-RA 5
6 CUSTOMER CHARGE ($/MONTH) $ 12.00 $ 12.00 $ 12.00 $ 12.00 6
7 METER CHARGE ($/MONTH) $ 6.80 $ 6.80 $ 6.80 $ 6.80 7
8 CONNECTED LOAD CHARGE $ 2.40 $ 2.20 $ 2.40 $ 2.20 8
($/KW/MONTH)
9 ON-PEAK ENERGY ($/KWH) $0.32902 $0.32902 9
10 PART-PEAK ENERGY ($/KWH) $0.07238 $0.07238 10
11 OFF-PEAK ENERGY ($/KWH) $0.07673 $0.05756 $0.07673 $0.05756 11
12 SCHEDULE AG-VA 12
13 CUSTOMER CHARGE ($/MONTH) $ 12.00 $ 12.00 $ 12.00 $ 12.00 13
14 METER CHARGE ($/MONTH) $ 6.80 $ 6.80 $ 6.80 $ 6.80 14
15 CONNECTED LOAD CHARGE $ 2.40 $ 2.20 $ 2.40 $ 2.20 15
($/KW/MONTH)
16 ON-PEAK ENERGY ($/KWH) $0.32394 $0.32394 16
17 PART-PEAK ENERGY ($/KWH) $0.07126 $0.07126 17
18 OFF-PEAK ENERGY ($/KWH) $0.07386 $0.05668 $0.07386 $0.05668 18
19 SCHEDULE AG-4A 19
20 CUSTOMER CHARGE ($/MONTH) $ 12.00 $ 12.00 $ 12.00 $ 12.00 20
21 METER CHARGE ($/MONTH) $ 6.80 $ 6.80 $ 6.80 $ 6.80 21
22 CONNECTED LOAD CHARGE $ 2.40 $ 2.20 $ 2.40 $ 2.20 22
($/KW/MONTH)
23 ON-PEAK ENERGY ($/KWH) $0.32436 $0.32436 23
24 PART-PEAK ENERGY ($/KWH) $0.07135 $0.07135 24
25 OFF-PEAK ENERGY ($/KWH) $0.06524 $0.05674 $0.06524 $0.05674 25
</TABLE>
C-15
<PAGE>
EXHIBIT C
ADJUSTMENT RATE TABLES
PAGE-16
PACIFIC GAS AND ELECTRIC COMPANY
CURRENT AND PROPOSED AGRICULTURAL RATES
<TABLE>
<CAPTION>
LINE 6/10/96 RATES 6/10/96 RATES 1/1/98 RATES 1/1/98 RATES LINE
NO. SUMMER WINTER SUMMER WINTER NO.
<C> <S> <C> <C> <C> <C> <C>
1 SCHEDULE AG-5A 1
2 CUSTOMER CHARGE ($/MONTH) $ 12.00 $ 12.00 $ 12.00 $ 12.00 2
3 METER CHARGE ($/MONTH) $ 6.80 $ 6.80 $ 6.80 $ 6.80 3
4 CONNECTED LOAD CHARGE $ 5.50 $ 5.50 $ 5.50 $ 5.50 4
($/KW/MONTH)
5 ON-PEAK ENERGY ($/KWH) $0.23938 $0.23938 5
6 PART-PEAK ENERGY ($/KWH) $0.05516 $0.05516 6
7 OFF-PEAK ENERGY ($/KWH) $0.04926 $0.04388 $0.04926 $0.04388 7
8 SCHEDULE AG-6A 8
9 CUSTOMER CHARGE ($/MONTH) $ 12.00 $ 12.00 $ 12.00 $ 12.00 9
10 CONNECTED LOAD CHARGE $ 5.50 $ 550 $ 5.50 $ 5.50 10
($/KW/MONTH)
11 ENERGY CHARGE ($/KWH) $0.08280 $0.04817 $0.08280 $0.04817 11
12 SCHEDULE AG-1B 12
13 CUSTOMER CHARGE($/MONTH) $ 16.00 $ 16.00 $ 16.00 $ 16.00 13
14 MAXIMUM DEMAND CHARGE 14
15 SECONDARY VOLTAGE $ 2.90 $ 1.75 $ 2.90 $ 1.75 15
($/KW/MONTH)
16 PRIMARY VOLTAGE DISCOUNT $ 0.40 $ 0.30 $ 0.40 $ 0.30 16
($/KW/MONTH)
17 ENERGY CHARGE ($/KWH) $ 011984 $0.11984 $0.11984 $0.11984 17
18 RATE LIMITER ($/KWH) $1.19780 $1.19780 $1.19780 $l.19780 18
19 SCHEDULE AG-RB 19
20 CUSTOMER CHARGE ($/MONTH) $ 16.00 $ 16.00 $ 16.00 $ 16.00 20
21 METER CHARGE ($/MONTH) $ 6.00 $ 6.00 $ 6.00 $ 6.00 21
22 ON-PEAK DEMAND CHARGE $ 2.75 $ 2.75 22
($/KW/MONTH)
23 MAXIMUM DEMAND CHARGE 23
($/KW/MONTH)
24 SECONDARY VOLTAGE $ 2.90 $ 1.75 $ 2.90 $ 1.75 24
($/KW/MONTH)
25 PRIMARY VOLTAGE DISCOUNT $ 0.40 $ 0.30 $ 0.40 $ 0.30 25
($/KW/MONTH)
26 ON-PEAK ENERGY ($/KWH) $0.28143 $0.28143 26
27 PART-PEAK ENERGY ($/KWH) $0.08027 $0.08027 27
28 OFF-PEAK ENERGY ($/KWH) $0.08254 $0.06383 $0.08254 $0.06383 28
29 RATE LIMITER ($/KWH) $l.19780 $l.19780 $l.19780 $l.19780 29
</TABLE>
C-16
<PAGE>
EXHIBIT C
ADJUSTMENT RATE TABLES
PAGE 17
PACIFIC GAS AND ELECTRIC COMPANY
CURRENT AND PROPOSED AGRICULTURAL RATES
<TABLE>
<CAPTION>
LINE 6/10/96 RATES 6/10/96 RATES 1/1/98 RATES 1/1/98 RATES LINE
NO. SUMMER WINTER SUMMER WINTER NO.
<C> <S> <C> <C> <C> <C> <C>
1 SCHEDULE AG-VB 1
2 CUSTOMER CHARGE ($/MONTH) $ 16.00 $ 16.00 $ 16.00 $ 16.00 2
3 METER CHARGE ($/MONTH) $ 6.00 $ 6.00 $ 6.00 $ 6.00 3
4 ON-PEAK DEMAND CHARGE $ 2.75 $ 2.75 4
($/KW/MONTH)
5 MAXIMUM DEMAND CHARGE 5
($/KW/MONTH)
6 SECONDARY VOLTAGE $ 2.90 $ 1.75 $ 2.90 $ 1.75 6
($/KW/MONTH)
7 PRIMARY VOLTAGE DISCOUNT $ 0.40 $ 0.30 $ 0.40 $ 0.30 7
($/KW/MONTH)
8 ON-PEAK ENERGY ($/KWH) $ 0.24935 $ 0.24935 8
9 PART-PEAK ENERGY ($/KWH) $0.07764 $0.07764 9
10 OFF-PEAK ENERGY ($/KWH) $ 0.07737 $0.06172 $ 0.07737 $0.06172 10
11 RATE LIMITER ($/KWH) $ l.19780 $l.19780 $ l.19780 $l.19780 11
12 SCHEDULE AG-4B 12
13 CUSTOMER CHARGE ($/MONTH) $ 16.00 $ 16.00 $ 16.00 $ 16.00 13
14 METER CHARGE ($/MONTH) $ 6.00 $ 6.00 $ 6.00 600.14 14
15 ON-PEAK DEMAND CHARGE $ 2.75 $ 2.75 15
($/KW/MONTH)
16 MAXIMUM DEMAND CHARGE 16
($/KW/MONTH)
17 SECONDARY VOLTAGE $ 2.90 $ 1.75 $ 2.90 $ 1.75 17
($/KW/MONTH)
18 PRIMARY VOLTAGE DISCOUNT $ 0.40 $ 0.30 $ 0.40 $ 0.30 18
($/KW/MONTH)
19 ON-PEAK ENERGY ($/KWH) $ 0.20711 $ 0.20711 19
20 PART-PEAK ENERGY ($/KWH) $0.07182 $0.07182 20
21 OFF-PEAK ENERGY ($/KWH) $ 0.06499 $0.05710 $ 0.06499 $0.05710 21
22 RATE LIMITER ($/KWH) $ l.19780 $l.19780 $ l.19780 $l.19780 22
23 SCHEDULE AG-4C 23
24 CUSTOMER CHARGE ($/MONTH) $ 16.00 $ 16.00 $ 16.00 $ 16.00 24
25 METER CHARGE ($/MONTH) $ 6.00 $ 6.00 $ 6.00 $ 6.00 25
26 ON-PEAK DEMAND CHARGE $ 6.25 $ 6.25 26
($/KW/MONTH)
27 PARTIAL-PEAK DEMAND CHARGE $ 4.50 $ 0.40 $ 4.50 $ 0.40 27
($/KW/MONTH)
28 OFF-PEAK DEMAND CHARGE $ 1.50 $ 0.20 $ 1.50 $ 0.20 28
($/KW/MONTH)
29 ON-PEAK ENERGY ($/KWH) $ 0.08965 $ 0.08965 29
30 PART-PEAK ENERGY ($/KWH) $0.06 134 $0.08956 $0.06 134 $0.08956 30
31 OFF-PEAK ENERGY ($/KWH) $ 0.05214 $0.07417 $ 0.05214 $0.07417 31
</TABLE>
C-17
<PAGE>
EXHIBIT C
ADJUSTMENT RATE TABLES
PAGE 18
PACIFIC GAS AND ELECTRIC COMPANY
CURRENT AND PROPOSED AGRICULTURAL RATES
<TABLE>
<CAPTION>
LINE 6/10/96 RATES 6/10/96 RATES 1/1/98 RATES 1/1/98 RATES LINE
NO. SUMMER WINTER SUMMER WINTER NO.
<C> <S> <C> <C> <C> <C> <C>
1 SCHEDULE AG-5B 1
2 CUSTOMER CHARGE ($/MONTH) $ 16.00 $ 16.00 $ 16.00 $ 16.00 2
3 METER CHARGE ($/MONTH) $ 6.00 $ 6.00 $ 6.00 $ 6.00 3
4 ON-PEAK DEMAND CHARGE $ 2.70 $ 2.70 4
($/KW/MONTH)
5 MAXIMUM DEMAND CHARGE 5
($/KW/MONTH)
6 SECONDARY VOLTAGE $ 6.55 $ 4.40 $ 6.55 $ 4.40 6
7 PRIMARY VOLTAGE DISCOUNT $ 0.95 $ 0.65 $ 0.95 $ 0.65 7
8 TRANSMISSION VOLTAGE DISCOUNT $ 4.85 $ 325 $ 4.85 $ 325 8
9 ON-PEAK ENERGY ($/KWH) $0. 14294 $0.14294 9
10 PART-PEAK ENERGY ($/KWH) $0.04661 $0.04661 10
11 OFF-PEAK ENERGY ($/KWH) $ 0.04088 $0.03706 $0.04088 $0.03706 11
12 RATE LIMITER ($/KWH) $ l.19780 $l.19780 $l.19780 $l.19780 12
13 SCHEDULE AG-SC 13
14 CUSTOMER CHARGE ($/MONTH) $ 54.00 $ 54.00 $ 54.00 $ 54.00 14
15 METER CHARGE ($/MONTH) $ 6.00 $ 6.00 $ 6.00 $ 6.00 15
16 ON-PEAK DEMAND CHARGE $ 9.20 $ 9.20 16
($/KW/MONTH)
17 PARTIAL-PEAK DEMAND CHARGE $ 5.60 $ 0.70 $ S.60 $ 0.70 17
($/KW/MONTH)
18 OFF -PEAK DEMAND CHARGE $ 1.55 $ 0.10 $ 1.55 $ 0.10 18
($/KW/MONTH)
19 ON-PEAK ENERGY ($/KWH) $ 0.07781 $0.07781 19
20 PART-PEAK ENERGY ($/KWH) $ 0.04906 $0.05979 $0.04906 $0.05979 20
21 OFF-PEAK ENERGY ($/KWH) $ 0.03783 $0.04669 $0.03783 $0.04669 21
22 SCHEDULE AG-6B 22
23 CUSTOMER CHARGE ($/MONTH) $ 16.00 $ 16.00 $ 16.00 $ 16.00 23
24 MAXIMUM DEMAND CHARGE 24
($/KW/MONTH)
25 SECONDARY VOLTAGE $ 6.55 $ 4.40 $ 6.55 $ 4.40 25
26 PRIMARY VOLTAGE DISCOUNT $ 0.95 $ 0.65 $ 0.95 $ 0.65 26
27 ENERGY CHARGE ($/KWH) $ 0.06789 $0.04105 $0.06789 $0.04105 27
28 RATE LIMITER ($/KWH) $ l.19780 $l.19780 $l.19780 $l.19780 28
</TABLE>
C-18
<PAGE>
EXHIBIT C
ADJUSTMENT RATE TABLES
PAGE 19
PACIFIC GAS AND ELECTRIC COMPANY
CURRENT AND PROPOSED STREETLIGHTING RATES
<TABLE>
<CAPTION>
LINE 6/10/96 RATES 6/10/96 RATES 1/1/98 RATES 1/1/98 RATES LINE
NO. SUMMER WINTER SUMMER WINTER NO.
<C> <S> <C> <C> <C> <C> <C>
1 SCHEDULE LS-1 l
2 ENERGY CHARGE ($/KWH) $0.07097 $0.07097 $0.07097 $ 0.07097 2
3 SCHEDULE LS-2 3
4 ENERGY CHARGE ($/KWH) $0.07097 $0.07097 $0.07097 $0.070974 4
5 SCHEDULE LS-3 5
6 SERVICE CHARGE ($/METER/MO.) $ 3.00 $ 3.00 $ 3.00 $ 3.00 6
7 SWITCHING CHARGE ($/CIRCUIT) $ 3.25 $ 3.25 $ 3.25 $ 3.25 7
8 ENERGY CHARGE ($/KWH) $0.07097 $0.07097 $0.07097 $ 0.07097 8
9 SCHEDULE OL-1 9
10 ENERGY CHARGE ($/KWH) $0.07142 $0.07142 $0.07142 $ 0.07142 10
</TABLE>
C-19
<PAGE>
EXHIBIT D
SUMMARY OF ELECTRIC DEPARTMENT PROPERTY
<PAGE>
EXHIBIT D
PACIFIC GAS AND ELECTRIC COMPANY
RECORDED PLANT AND DEPRECIATION RESERVE
AS OF DECEMBER 31, 1996
(Thousands of Dollars)
<TABLE>
<CAPTION>
Electric
Department
----------
<S> <C>
Operative Plant 18,018,162
Depreciation Reserve 7,819,706
</TABLE>
D-1
<PAGE>
EXHIBIT E
RECORDED REVENUES, EXPENSES AND RATE OF RETURN
<PAGE>
EXHIBIT E
PACIFIC GAS AND ELECTRIC COMPANY
ALL OPERATING DEPARTMENTS
REVENUES, EXPENSES, RATE BASES AND RATES OF RETURN
YEAR 1996 RECORDED
(Thousands of Dollars)
<TABLE>
<CAPTION>
Line ELECTRIC OPERATING Line
No. DEPARTMENT DEPARTMENTS No.
<C> <S> <C> <C> <C>
1 Gross Operating Revenues $5,378,054 $ 7,191,258 1
Operating Expenses:
2 Production 2,435,833 2.949,158 2
3 Storage 0 5.031 3
4 Transmission 77.735 389,243 4
5 Distribution 356.088 498,222 5
6 Customer Accounts 215,231 323,600 6
7 Customer Service and Information 113.540 147,008 7
8 Administrative and General 520.240 852.371 8
9 Total Expenses Excluding 3,718,667 5.164,633 9
Taxes and Depreciation
Taxes:
10 Property 110.668 142.362 10
11 Payroll and Business 46,712 68.135 11
12 State Corporation Franchise 43,678 36,966 12
13 Federal Income 255,422 250,955 13
14 Total Taxes 456,480 498.418 14
15 Depreciation 597.678 831,213 15
16 Total Operating Expenses $4,772,825 $ 6,494,264 16
17 Net for Return $ 605,229 $ 696,994 17
18 Rate Base $8,996,733 $11,738,861 18
19 Rate of Return 6.73% 5.94% 19
</TABLE>
Note: (1) Excludes Gas Line 401
(2) Excludes Diablo Canyon
E-1
<PAGE>
EXHIBIT F
FORECASTED RESULTS OF OPERATIONS
<PAGE>
EXHIBIT F
PACIFIC GAS AND ELECTRIC COMPANY
RESULTS OF OPERATIONS
ELECTRIC DEPARTMENT - CPUC JURISDICTIONAL
YEAR 1998
(000)
PACIFIC GAS AND ELECTRIC COMPANY
RESULTS OF OPERATIONS
ELECTRIC DEPARTMENT - CPUC JURISDICTIONAL
YEAR 1998
(000)
<TABLE>
<CAPTION>
Present Rates (b) Proposed Rates
Line --------------------------- ----------------------------- Line
No. Authorized (a) Adjustments Adjusted Adjustments Total No.
- ---------------- -------------- ----------- --------- ----------- --------- ----
<C> <S> <C> <C> <C> <C> <C> <C>
1 Gross Operating Revenue 3,240,212 4,500,489 7,740,701 (411,516) 7,329,185 1
2 Less. CFA 0 1,543 1,543 1,543 2
3 CPUC Fee 0 9,257 9,257 9,257 3
4 CEE 0 27,772 27,772 27,772 4
--------- --------- --------- -------- ---------
5 Total Revenues 3,240,212 4,461,917 7,702,129 (411,516) 7,290,613 5
Operating Expense:
Expenses:
6 Reduced Financing Costs (407,560) (407,560) 6
7 ERAM/CTC 0 815,876 815,876 815,876 7
8 ECAC 0 3,570,083 3,570,083 3,570,083 8
9 CARE 0 33,067 33,067 33,067 9
10 EnergyCost 31 0 31 31 10
11 Production 263,974 0 263,974 263,974 11
12 Transmission 51,315 0 51,315 51,315 12
13 Distribution 244,752 0 244,752 244,752 13
14 Customer Accounts 100,955 0 100,955 100,955 14
15 Uncollectibles 7,889 10,709 18,597 (988) 17,609 15
16 Demand Side Management 105,901 0 105,901 105,901 16
17 Administrative and General 388,665 0 388,665 388,665 17
18 Franchise Requirements 23,352 32,182 55,534 (2,968) 52,566 18
19 Project Amortization 0 0 0 0 19
20 Compensation Adjustment (14,893) 0 (14,893) (14,893) 20
--------- --------- --------- -------- ---------
21 Subtotal Expenses 1,171,940 4,461,917 5,633,857 (411,516) 5,222,341 21
Taxes:
22 Superfund 1,743 0 1,743 1,743 22
23 Property 110,985 0 110,985 110,985 23
24 Payroll and Business 35,343 0 35,343 35,343 24
25 Other 1,162 0 1,162 1,162 25
26 State Corp Franchise 93,983 0 93,983 93,983 26
27 Federal Income 340,513 0 340,513 340,513 27
--------- --------- --------- -------- ---------
28 Subtotal Taxes 583,729 0 583,729 0 583,729 28
29 Depreciation 574,201 0 574,201 574,201 29
30 Fossil Decommissioning 32,512 0 32,512 32,512 30
31 Nuclear Decommissioning 32,706 0 32,706 32,706 31
--------- --------- --------- -------- ---------
32 Total Operating Expenses 2,395,088 4,461,917 6,857,005 (411,516) 6,445,489 32
33 Net for Return 845,124 0 845,124 0 845,124 33
34 Rate Base 8,945,646 0 8,945,646 0 8,945,646 34
35 Rate of Return 9.45% 9.45% 9.45% 35
</TABLE>
(a) As authorized in the 1996 GRC Decision 95-1 2-055, 1997 Cost of Capital
Decision 96-1 1 060, and Diablo Canyon Decommissioning Advice Letter 161 4-E.
----
(b) Revenues at Present 111197 Rates applied to 1998 billing determinants.
F-1
<PAGE>
EXHIBIT G
TAX METHOD OF DEPRECIATION
<PAGE>
EXHIBIT G
PACIFIC GAS AND ELECTRIC COMPANY
DEPRECIATION AND FEDERAL INCOME TAXES
The following statement is submitted in accordance with Rule 23(h) of the
Commission's Revised Rules of Procedure which requires, "A statement by
applicant as to which of the optional methods provided in the Internal Revenue
Code applicant has elected to employ in computing the depreciation deduction for
the purpose of determining its federal income tax payments, and whether
applicant has used the same method or methods in calculating federal income
taxes for the test period for rate-fixing purposes."
For financial statement purposes, depreciation of utility plant has been
computed on a straight-line remaining life basis based on the estimated
service lives of plant investments. For federal income tax purposes, the
company generally computes depreciation using the straight-line method for
tax property additions prior to 1954 and liberalized depreciation on tax
property additions after 1954 and prior to 1981, which includes the Class
Life and Asset Depreciation Range Systems. For financial reporting and
rate-fixing purposes, "flow-through accounting" has been adopted for such
properties. However, for tax property additions in 1981 through 1986, as
well as qualified transition property for subsequent years, the company
computes it tax depreciation using the Accelerated Cost Recovery System
(ACRS). The effect of the differences between ACRS and straight-line
depreciation is normalized in accordance with the Economic Recovery Tax
Act of 1981. Due to the Tax Reform Act of 1986, the company computes its
tax depreciation using the Modified Accelerated Cost Recovery System for
qualified tax property additions in 1987 and subsequent years.
Normalizations will still be in effect for these property additions.
G-1
<PAGE>
EXHIBIT H
AFFECTED GOVERNMENTAL ENTITIES
<PAGE>
EXHIBIT H
SERVICE OF NOTICE OF APPLICATION
In accordance with Rule 24, Applicant will mail a notice to the following,
stating in general terms its proposed change in rates.
State of California
-------------------
To the Attorney General and the Department of General Services.
State of California
Office of Attorney General
50 Fremont Street
San Francisco, CA 94105
and
Department of General Services
Office of Buildings and Grounds
505 Van Ness Avenue, Room 2012
San Francisco, CA 94102
Counties
--------
To the County Counsel or District Attorney and the County Clerk in the
following counties:
<TABLE>
<CAPTION>
<S> <C> <C>
Alameda Marin Santa Clara
Alpine Mariposa Santa Cruz
Amador Mendocino Shasta
Butte Merced Sierra
Calaveras Monterey Siskiyou
Colusa Napa Solano
Contra Costa Nevada Sonoma
El Dorado Placer Stanislaus
Fresno Plumas Sutter
Glenn Sacramento Tehama
Humboldt San Benito Trinity
Kern San Francisco Tulare
Kings San Joaquin Tuolumne
Lake San Luis Obispo Yolo
Lassen San Mateo Yuba
Madera Santa Barbara
</TABLE>
H-1
<PAGE>
EXHIBIT H
Municipal Corporations
----------------------
To the City Attorney and the City Clerk of the following municipal
corporations:
<TABLE>
<CAPTION>
<S> <C> <C>
Alameda Davis Lemoore
Albany Del Rey Oakes Lincoln
Amador City Dinuba Live Oak
American Canyon Dixon Livermore
Anderson Dos Palos Livingston
Angels Dublin Lodi
Antioch East Palo Alto Lompoc
Arcata El Cerrito Loomis
Arroyo Grande Emeryville Los Altos
Arvin Escalon Los Altos Hills
Atascadero Eureka Los Banos
Atherton Fairfax Los Gatos
Atwater Fairfield Madera
Auburn Ferndale Manteca
Avenal Firebaugh Maricopa
Bakersfield Folsom Marina
Belmont Fort Bragg Martinez
Belvedere Fortuna Marysville
Benicia Foster City McFarland
Berkeley Fowler Mendota
Biggs Fremont Menlo Park
Blue Lake Fresno Merced
Brentwood Gilroy Mill Valley
Brisbane Gonzales Millbrae
Buellton Grass Valley Milpitas
Burlingame Greenfield Monte Sereno
Calistoga Gridley Monterey
Campbell Grover Beach Moraga
Capitola Guadalupe Morgan Hill
Carmel Gustine Morro Bay
Chico Half Moon Bay Mountain View
Chowchilla Hanford Napa
Clayton Hayward Newark
Clearlake Healdsburg Nevada City
Cloverdale Hercules Newman
Clovis Hillsborough Novato
Coalinga Hollister Oakdale
Colfax Huron Oakland
Colma lone Orange Cove
Colusa Isleton Orinda
Concord Jackson Orland
Corcoran Kerman Oroville
Corning King City Pacific Grove
Corte Madera Kingsburg Pacifica
Cotati Lafayette Palo Alto
Cupertino Lakeport Paradise
Daly City Larkspur Parlier
Danville Lathrop Paso Robles
</TABLE>
H-2
<PAGE>
EXHIBIT H
<TABLE>
<CAPTION>
<S> <C> <C>
Patterson San Anselmo Sonora
Petaluma San Bruno South San Francisco
Piedmont San Carlos Stockton
Pinole San Francisco Suisun City
Pismo Beach San Joaquin Sunnyvale
Pittsburg San Jose Sutter Creek
Placerville San Juan Bautista Taft
Pleasant Hill San Leandro Tehama
Pleasanton San Luis Obispo Tiburon
Plymouth San Mateo Tracy
Point Arena San Pablo Trinidad
Portola Valley San Rafael Ukiah
Red Bluff San Ramon Union City
Redding Sand City Vacaville
Redwood City Sanger Vallejo
Reedley Santa Clara Walnut Creek
Richmond Santa Cruz Wasco
Rio Dell Santa Maria Watsonville
Rio Vista Santa Rosa West Sacramento
Ripon Saratoga Wheatland
Riverbank Sausalito Williams
Rocklin Scotts Valley Willits
Rohnert Park Seaside Willows
Roseville Sebastopol Windsor
Ross Selma Winters
Sacramento Shafter Woodland
Saint Helena Shasta Lake Woodside
Salinas Soledad Yountville
Solvang Yuba City
Sonoma
</TABLE>
H-3
<PAGE>
Application No.:
------------------
Exhibit No.:
----------------------
Date: May 6, 1997
----------------------------
PACIFIC GAS AND ELECTRIC COMPANY
RATE REDUCTION BOND FINANCING
PG&E LOGO
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
RATE REDUCTION BOND FINANCING
TABLE OF CONTENTS
<TABLE>
<CAPTION>
Chapter Title Page
- ----------------- --------------------------------------------------- ------
<S> <C> <C>
1 INTRODUCTION
A. Introduction 1-1
B. Overview of the Testimony 1-2
2 ASSET BACKED SECURITY MARKET
A. Overview of Assets Backed Securities 2-1
1. Bankruptcy and Legal Issues in Securitizations 2-2
2. Accounting Issues and Securitization
3. Tax Issues in Securitization 2-3
4. Servicing Issues in Securitization 2-4
5. Ratings of Asset Backed Securities 2-6
6. Size and Growth of the Asset Backed Securities
Market 2-7
7. Pricing for Asset Backed Securities 2-10
B. Application of Asset Backed Finance to the
Restructuring of the Electric Utility Industry 2-11
3 TRANSACTION OVERVIEW
A. Introduction 3-1
B. Overview of AB 1890 3-1
C. Proposed Transaction Structure 3-3
D. Factors Determining the Proposed Transaction
Structure 3-4
1. RRB Credit Rating Issues 3-5
2. Tax Issues 3-10
3. Accounting Issues 3-12
E. Servicing the RRBs 3-12
F. Timing and Sizing of the Proposed Transaction 3-16
G. RRB Characteristics 3-18
</TABLE>
i
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
RATE REDUCTION BOND FINANCING
TABLE OF CONTENTS
(Continued)
<TABLE>
<CAPTION>
Chapter Title Page
- ----------------- --------------------------------------------------- ------
<S> <C> <C>
H. Transaction Costs and Use of Proceeds 3-19
4 SIZE OF THE RATE REDUCTION BOND ISSUANCE
A. Introduction 4-1
B. Sizing of the RRB Issuance 4-1
1. Overview 4-1
a. Target Revenue Reductions 4-2
b. Gross Avoided Revenue Requirement 4-3
c. RRB Debt Service Revenue Requirement 4-3
d. Net Change in Revenue Requirements 4-3
2. Customer Benefits 4-5
5 REVENUE REQUIREMENTS AND RATEMAKING MECHANISM
A. Introduction 5-1
B. CTC Ratemaking Mechanism 5-2
1. Overview 5-2
2. Proposed Mechanics to Incorporate
RRBs and 10 Percent Rate Reduction
and to Prevent Cost Shifting 5-3
C. Financial Accounting 5-5
D. RRB Memorandum Account 5-5
1. RRB Proceeds Adjustment Memorandum
Subaccount 5-5
2. Post-Rate Freeze Period
a. Servicing Fees Memorandum Subaccount 5-5
b. Carrying Cost Memorandum Subaccount 5-5
c. SPE Investment Earnings Memorandum Subaccount 5-8
d. Over collateralization Memorandum Subaccount 5-8
e. RRB Proceeds Adjustment Memorandum Subaccount 5-9
f. Post-Rate Freeze Period
Financed Tax Memorandum Subaccount 5-9
6 RATE PROPOSAL
A. Introduction
B. Discount Applicability 6-1
C. Calculation of Discount 6-1
D. Calculation of FTA Charge 6-2
E. Non-Bypassability 6-3
F. Fixed Transition Amount Charge 6-4
True-Up Mechanism 6-5
</TABLE>
ii
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
RATE REDUCTION BOND FINANCING
TABLE OF CONTENTS
(Continued)
<TABLE>
<CAPTION>
Chapter Title Page
- ----------------- --------------------------------------------------- ------
<S> <C> <C>
F. Fixed Transition Amount Charge True-Up
Mechanism 6-5
APPENDIX A DESCRIPTION OF SIZING MODEL
A. Introduction A-1
B. Sizing of the Rate Reduction Bond Issuance A-1
1. Target Residential and Small Commercial A-1
Customer Revenue Reduction
2. Gross Avoided Revenue Requirements A-3
3. RRB Debt Service Revenue Requirements A-6
4. Net Revenue Requirement Reduction A-7
5. Customer Benefits A-8
C. Use of a Generic Transition Cost A-8
APPENDIX B ELECTRIC SALES FORECAST
A. Introduction B-1
B. Electric Sales Forecast Methodology B-1
C. Cost Separation Decision B-3
APPENDIX C PRO FORMA PRELIMINARY STATEMENT LANGUAGE
APPENDIX D DESCRIPTION OF CASH FLOW MODEL
A. Introduction D-1
B. Overview of the RRB Cash Flow Model D-1
C. FTA Charge Calculation D-1
</TABLE>
-iii-
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
CHAPTER 1
INTRODUCTION
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
CHAPTER 1
INTRODUCTION
A. INTRODUCTION
------------
Pacific Gas and Electric Company (PG&E) is filing this application as
a part of the ongoing electric industry restructuring (OIR/OII
94-04-031/94-04-032) initiated by the California Public Utilities
Commission (Commission), and in response to the mandates of Assembly Bill
1890 (AB 1890), signed into law on September 23, 1996 (1996 Cal. Stat. ch.
854).
The purpose of this application, including this supporting testimony
is to obtain from the Commission a Financing Order authorizing the issuance
of Rate Reduction Bonds (RRBs or Bonds) in an aggregate principal amount of
up to $3.5 billion. This application also seeks approval, conditioned on
timely and sufficient issuance of the RRBs, of a 10 percent rate reduction,
beginning January 1, 1998, and continuing through the electric industry
restructuring's rate freeze period.
The issuance of RRBs will support a 10 percent rate reduction for
residential and small commercial customers by lowering the carrying cost on
a portion of PG&E's transition costs and by spreading out the recovery of
these transition costs over the life of the Bonds.
PG&E estimates the net present value benefits to its residential and
small commercial customers from the issuance of RRBs and the associated 10
percent rate reduction will total approximately $470 million.
Satisfactory and timely Commission approval of this application will
enable the issuance of RRBs in the fourth quarter of this year and the
implementation of the rate reduction on January 1, 1998.
1-1
<PAGE>
B. OVERVIEW OF THE TESTIMONY
-------------------------
1. Chapter 2: Asset Backed Security Market
----------------------------------------
RRBs are part of a category of financial instruments generally
described as asset backed securities.
Chapter 2 provides a general description of asset backed securities,
including how bankruptcy, accounting and tax considerations can have an
effect on the structure of asset backed security transactions. Chapter 2
also discusses the credit ratings of asset backed securities, the size
of the asset backed security market, and the pricing of these
securities. Finally, Chapter 2 addresses the expected market receptivity
to the RRBs.
2. Chapter 3: Transaction Overview
--------------------------------
Chapter 3 describes AB 1890 as it relates to the RRBs, and then
describes the RRB transaction. It explains the entities anticipated to
be involved and their roles, including PG&E, an affiliated Special
Purpose Entity (SPE), and an Issuer which may be the California
Infrastructure and Economic Development Bank (Infrastructure Bank) an
affiliate of the Bank, or entity approved by the Bank.
Chapter 3 also addresses the bankruptcy, tax and accounting
considerations that affect the structure of the RRB transaction.
3. Chapter 4: Size of the Rate Reduction Bond Issuance
----------------------------------------------------
Chapter 4 describes how the RRB issuance amount is established to
ensure that it is consistent with the 10 percent rate reduction provided
to residential and small commercial customers. Chapter 4 also estimates
the net present value benefit that the 10 percent rate decrease and the
RRB transaction are expected to provide to these customers.
4. Chapter 5: Revenue Requirements and Ratemaking Mechanisms
----------------------------------------------------------
Chapter 5 addresses how the effect of the RRBs will be incorporated
into the Competition Transition Charge (CTC) Ratemaking Mechanisms,
described in
1-2
<PAGE>
PG&E's CTC Application (A.96-08-070), and how these mechanisms will be
used to determine when the rate freeze period ends. Chapter 5 also
explains how PG&E will ensure that residential and small commercial
customers receive all net benefits resulting from any RRB issuance.
5. Chapter 6: Rate Proposal
-------------------------
Chapter 6 identifies the PG&E customers who will be eligible for the
10 percent rate reduction, and how the 10 percent rate reduction will
be reflected on those customers' bills. It describes the calculation of
the Fixed Transition Amounts (FTA) charge, through which Bond principal
and interest, as well as other items such as servicing fees, will be
collected from residential and small commercial customers receiving the
rate reduction, and the FTA charge true-up mechanism.
Chapter 6 also explains how the non-bypassable feature of the FTA
charge will be implemented.
6. Appendix A
----------
Appendix A contains a line-by-line explanation of PG&E's RRB
spreadsheet sizing and benefit calculation model.
7. Appendix B
----------
Appendix B provides PG&E's electric sales forecast used to size the
RRBs.
8. Appendix C: Pro Forma Preliminary Statement Language
-----------------------------------------------------
Appendix C provides pro forma Preliminary Statement language for the
RRB entry to the CTC Revenue Account, and for the Rate Reduction Bond
Memorandum Account, which are both described in Chapter 5.
9. Appendix D: Description of Cash Flow Model
-------------------------------------------
Appendix D contains a description of the RRB Cash Flow Model which
will be used to calculate the FTA charges and the periodic FTA charge
adjustments.
10. Appendix E: Proposed Fixed Transition Amount Tariff Language
-------------------------------------------------------------
Appendix E provides pro forma tariff language for the FTA charges.
1-3
<PAGE>
11. Appendix F
----------
Appendix F sets forth the qualifications of each of the PG&E
witnesses sponsoring a portion of this testimony.
12. Appendix G
----------
Appendix G is a glossary that contains definitions of the important
terms used in this testimony.
1-4
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
CHAPTER 2
ASSET BACKED SECURITY MARKET
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
CHAPTER 2
ASSET BACKED SECURITY MARKET
A. OVERVIEW OF ASSET BACKED SECURITIES
------------------------------------
The Asset Backed Securities (ABS) market developed as an outgrowth of
the Mortgage Backed Securities (MBS) market in the mid-1980s. Pools of
mortgage loans were routinely packaged into highly rated, liquid and
marketable securities which were primarily sold to institutional investors.
Payments on the underlying loans were used to pay interest and principal on
the offered securities. In addition, investors held security interests in
the homes as a means of enhancing repayment of the loans in the event of
defaults. The ABS market expanded this technology to include a variety of
consumer and financial assets which have predictable cash flow streams that
are commonly securitized today. Issuers have embraced securitization as a
funding tool because it can provide low-cost financing, capital savings
(when an issuer is faced with leverage restrictions), improved balance
sheet liquidity and other financial ratios, management of interest rate
risk, and an alternative funding source.
While the MBS market provided the foundation for the ABS market, ABS
products require customization based on the type of collateral being
securitized.
Certain types of loans, such as automobile loans and home equity
loans, have well-defined repayment schedules with stated terms and interest
rates; others such as credit card receivables and inventory financing loans
are characterized by periodic borrowings, repayments and reborrowings.
Securitizations of automobile and home equity loans, known as amortizing
loans, can pass through to investors the underlying monthly payment on the
loan as payment of interest and principal. The principal portion serves to
reduce or amortize the outstanding amount of the security while interest is
payable on the outstanding principal balance. Since these payments are
generally passed
2-1
<PAGE>
through to investors as received, the maturity and repayment schedule of
the ABS would generally match the maturity and repayment schedule of the
underlying loans.
The securitization process involves a comprehensive analytical
undertaking. It includes a wide array of considerations such as the
bankruptcy, tax and accounting treatment of the structures, as well as
servicing and systems issues associated with the underlying assets.
1. Bankruptcy and Legal Issues in Securitizations
----------------------------------------------
In a securitization, steps are taken to legally separate the
underlying assets from the bankruptcy estate of the originating company in
order to achieve credit ratings above that of the company. The assets are
typically contributed or sold to a bankruptcy-remote Special Purpose Entity
(SPE). Rating agencies generally (1)require the SPE to include two or more
independent members on its board of directors, in the case of a
corporation, or an independent trustee, in the case of a trust, (2)impose
restrictions on the SPE's ability to voluntarily declare bankruptcy or to
engage in corporate reorganizations, and (3)limit the activities of the SPE
to those related to the securitization. Legal counsel normally renders a
"true sale" opinion, which states that the assets have been sold for
bankruptcy purposes to the SPE, and opines that these assets would not be
part of the bankruptcy estate of the originating company and thus would not
be available to creditors of the company upon its bankruptcy.
In the absence of credit enhancement, as discussed below, the rating
of the ABS would be based exclusively on the credit quality of the
underlying assets. As this credit quality is not normally of the highest
rating category, the company may add various forms of credit enhancement to
the assets in order to achieve a higher rating. This credit enhancement may
consist of overcollateralization (the sale or pledging of assets in excess
of the amount necessary to repay the financed amount), cash reserve
accounts, or a surety bond or letter of credit provided by a "AAA"
institution. A
2-2
<PAGE>
company thus, for example, may be able to issue "AAA" ABS and significantly
reduce its borrowing costs. The vast majority of ABS today are structured
to achieve "AAA" ratings to take advantage of the associated borrowing cost
savings.
2. Accounting Issues in Securitization
-----------------------------------
Securitizations are most typically structured as a "sale" for
accounting purposes to achieve off-balance sheet treatment, but a number of
on-balance sheet securitization transactions which represent financings
from an accounting perspective have also been executed.
In an on-balance sheet transaction, the assets may nonetheless be
transferred in a "true sale" transaction to a bankruptcy-remote SPE
affiliated with the originator in order to achieve the desired level of
bankruptcy protection. The SPE then issues debt securities to investors.
The assets and liabilities associated with the securitization are
consolidated with the financial statements of the originator despite the
asset transfer to the affiliated bankruptcy-remote entity which actually
issues the debt securities. This form of securitization is essentially a
bankruptcy-remote form of collateralized debt and is accounted for as a
debt financing.
3. Tax Issues in Securitization
----------------------------
From a tax perspective, two basic issues must be evaluated in
structuring an ABS transaction. First, the tax status of the SPE must be
evaluated to determine whether the entity is taxed separately from the
originating company as a corporation, or whether it is treated as a
"transparent" entity for tax purposes. Securitizations are typically
structured to avoid entity-level taxation by employing an SPE such as a
partnership, grantor trust or division of the originating company for tax
purposes, since an entity-level tax would reduce the cash flow available to
investors.
The second part of the tax analysis evaluates the ownership of the
securitized assets for tax purposes. Securitizations are typically either
characterized as a sale for tax purposes, in which case the originator is
deemed to have sold the assets to
2-3
<PAGE>
investors for tax purposes, or as debt, in which case the assets are deemed
to have been "pledged" to secure the originator's debt for tax purposes. A
tax sale of assets generates an immediate tax liability to the originator
on any gain associated with the sale.
Tax debt characterization means that the assets are still deemed to be
owned by the originator for tax purposes, which defers any immediate tax
liability. Instead, taxes will be payable over time as the revenues, in
respect of the asset, are received. For tax purposes, the originator will
continue to be the owner of the assets, will report income generated by the
assets, and will deduct interest expense payable by the SPE. Tax counsel
typically requires that the SPE have a minimum level of at-risk equity to
support debt treatment for tax purposes.
Ultimately, the structure of the securitization transaction will be
driven by a particular originator's tax and accounting goals in the context
of what can be achieved in these areas under the applicable legal, tax,
accounting and regulatory framework.
4. Servicing Issues in Securitization
----------------------------------
Since the originating entity is no longer the owner of the assets from
a legal perspective, its function in the ABS transaction is usually limited
to acting as a servicer. Its responsibilities include preparing and mailing
customer statements, collecting payments from these obligors, resolving
customer disputes and distributing collections to ABS investors. The
originating entity as servicer for the securitization is expected to act
with the same level of care and to treat the securitized assets in the same
manner as if the assets had not been sold. The servicer also records and
reports the amount of collections and the performance of the overall pool
of assets for ABS investors. Because investors look to the assets for
repayment (and not to any independent obligation of the originating
company), rating agency and investor due diligence focuses on the quality
and experience of the
2-4
<PAGE>
servicer. Poor servicing could result in delays in payment or losses to
investors. Typically in ABS transactions, the servicer, once approved,
cannot resign (unless it is illegal for it to continue) or transfer
servicing except to a successor corporate entity. Additionally, servicers
whose debt ratings are not consistent with the rating of the transaction
(i.e.,investment grade) are required to make arrangements, such as setting
up an independently controlled lock box account at a financial institution
(normally the trustee) for remittance of cash payments from customers or
obligors, obtaining letters of credit, or providing additional credit
enhancement to assure that the amounts collected by the servicer on the
assets will be turned over to investors.
The servicer normally earns a fee for servicing the assets, consistent
with the costs of servicing similar assets. The servicing fee is usually
set at a rate to economically induce other servicers into servicing the
assets should the original servicer be unable to continue due to its
bankruptcy or default. The following table provides a snapshot of servicing
fees on various asset types. These fees are a percentage of the ABS
principal balance outstanding.
<TABLE>
<CAPTION>
SERVICING FEE
-------------
<S> <C>
Credit Cards 2.00% per annum
Automobile Loans 1.00%
Home Equity Loans 0.50%-0.75%
Manufactured Housing 0.75%-1.25%
Source: Recent ABS Prospectuses.
</TABLE>
The fees listed above reflect servicing costs for high-quality
obligors. Servicing fees for low-quality obligors are generally higher,
since the costs of servicing increase as the servicer is required to spend
a substantially greater amount of time ensuring that payments are made on
the most timely basis. For example, the
2-5
<PAGE>
servicing fees on a subprime automobile ABS transaction (loans to low-
quality obligors) are in the range of 3.00 to 3.50 percent per annum of the
average ABS principal amount outstanding.
5. Ratings of Asset Backed Securities
----------------------------------
From a credit perspective, the goal of a securitization is to achieve
a rating for the transaction based primarily on the credit quality of the
pledged or sold assets, with little or no consideration of the credit
quality of the seller or originator. In evaluating the credit quality of a
securitization transaction, the rating agencies typically focus on the
following issues:
. Credit risk of the assets
. Diversification of the asset pool
. Cash flow generated by the assets
. Structure of the ABS
. Servicing and collections ability and experience of the servicer
. Legal issues associated with the structure
. Credit enhancement
The main credit risk in a securitization related to the assets is the
potential for impairment of cash flows resulting from delinquencies or
losses on the pledged or sold assets. Depending on the structure of the
securitization, credit losses or cash flow disruption due to delinquencies
or losses may cause an inability to meet scheduled debt service. The rating
agencies will also evaluate the ability of interest earned on the assets to
support the ABS interest (which may be either a fixed or a floating rate)
and cover losses. Additionally, the rating agencies will analyze the size
and diversity of the obligor base as well as any geographic- or product-
specific concentrations in the pool in order to determine whether these
factors could significantly impact the credit characteristics of the pool.
Rating agency review of ABS assets is based on a statistical analysis and
the "law of large numbers" and,
2-6
<PAGE>
accordingly, securitization pools which are not sufficiently large and
diverse, or which have a single obligor representing a significant portion
of the assets, may not be cost effective.
The structure of the ABS transaction is also an important factor in
the rating agency analysis. For multiple class structures with several
credit ratings, the priority of interest and principal payments is integral
to assigning credit support levels. Finally, a servicer's collections
ability, credit quality (as defined by the rating agencies), and business
experience will be reviewed by the rating agencies as part of their due
diligence.
Credit enhancement, usually in the form of overcollateralization (the
pledge of more assets than liabilities), cash reserve funds or third-party
credit support is typically required to mitigate credit and liquidity risks
(up to the desired rating level) and ensure the full and timely payment of
the securities. Credit enhancement is sized by applying increasingly
stressful assumptions for each successively higher rating category. Note
that a higher credit rating level than that of the company can only be
achieved with the receipt of a "true-sale" opinion by the rating agencies.
If steps are not taken to legally separate the underlying assets from the
bankruptcy estate of the originating company, then the rating agencies
would not be able to rate the transaction generally more than two notches
("A-" versus "A+") higher than the credit rating of the company.
6. Size and Growth of the Asset Backed Securities Market
-----------------------------------------------------
The first public ABS was issued in 1985 by Sperry Lease Finance which
securitized computer leases. A variety of assets have been securitized in
the public markets since the inception of the ABS market, including credit
card receivables, trade receivables, automobile loans and leases, student
loans, home equity loans and lines of credit, equipment leases,
manufactured housing contracts, unsecured consumer loans and a number of
other less traditional assets. The following table
2-7
<PAGE>
shows a breakdown of 1996 ABS public issuance by asset type. Note that
nearly 20percent of 1996 public issuance was comprised of other asset
types, higher than in any other year in the ABS market.
<TABLE>
<CAPTION>
VOLUME PERCENTAGE
------ ----------
<S> <C> <C>
Credit Cards $46.5 bb 31.0%
Home Equity & Manuf. Housing $33.8 22.6
Automobile Loans $33.3 22.2
Student Loans $ 9.2 6.1
Other Asset Types $27.1 18.1
----- -----
Total $149.9 bb 100.0%
========= =====
</TABLE>
Source: Morgan Stanley & Co.
While the annual new issue volume in the public ABS market grew from
approximately $1 billion in 1985 to $59billion in 1993, even more
spectacular growth in the market has taken place in recent years. Between
1993 and 1996, the market has grown in excess of 50percent per annum, and
in 1995 eclipsed the $100billion mark for the first time. The following
graph shows annual issuance from 1985 to 1997. As noted in the graph, total
1997 ABS issuance is expected to exceed $180billion with much of the growth
expected to be fueled by home equity loans, student loans, equipment leases
and utility transition costs.
2-8
<PAGE>
[PLOT POINTS TO COME]
Source: Morgan Stanley & Co.
1996 was an especially strong year for the ABS market. Several weeks
saw issuance in excess of $7 billion. The ABS market was repeatedly able to
absorb multi-billion dollar transactions successfully, and in 1996 there
were over 20 transactions issued in excess of $1.0 billion. Indeed, the
largest public market securitization transaction in the history of the ABS
market was completed during 1996 and totaled over $4.0 billion. The
following table lists some of these large issues.
<TABLE>
<CAPTION>
ISSUE DATE ISSUER SIZE ASSET TYPE
- ---------- ------ ---- ----------
<S> <C> <C> <C>
2/29/96 Sallie Mae Student Loan Trust 1996-1 $1.5 bb Student Loans
3/13/96 Airplanes Pass-Through Trust $4.0 bb Airplane Leases
3/21/96 Premier Auto Trust 1996-1 $1.2 bb Automobile Loans
4/23/96 Discover Card Master Trust 1996-4 $1.0 bb Credit Cards
6/13/96 Ford Credit Auto Owner Trust 1996-A $1.0 bb Automobile Loans
10/9/96 Capita Equipment Receivables Trust 1996-1 $3.1 bb Equipment Leases
11/6/96 Chase Manhattan Credit Card Master Trust 1996-4 $1.0 bb Credit Cards
</TABLE>
Source: Morgan Stanley & Co.
2-9
<PAGE>
7. Pricing for Asset Backed Securities
-----------------------------------
The amortization schedule of the RRBs is similar to other amortizing
ABS issues since the RRB investors are expected to receive quarterly
payments of interest and principal. Since principal is payable quarterly,
investors are generally quoted a spread to the weighted average life of the
amortizing ABS. Weighted average life refers to the average amount of time
an investor is expected to receive the full amount of principal. Note that
the average life for a bullet security (the typical corporate bond
principal payment structure) is equal to the period of time between the
issuance date and the maturity date. Because the investor in an amortizing
ABS is receiving principal payments on a periodic basis, the investor is
subject to reinvestment risk on the principal amount received. If overall
interest rates have gone down since the ABS was initially purchased, the
investor would be forced to invest the returned principal in a lower
yielding investment. Because the amortizing ABS investor is subject to this
reinvestment risk, the amortizing ABS investor demands a spread premium
relative to a corporate bond investment for a comparable average life.
Additionally, despite the high credit ratings of ABS, they do not
generally price at basis point spreads that are comparable to corporate
bond spreads for a given rating level (one basis point equals .01percent).
ABS investors continue to demand a spread premium in relation to corporate
bonds as the ABS represents a "structured" rating based predominantly on
the structure and underlying collateral. The following table compares
spreads on "AAA" manufactured housing ABS to spreads on industrial "AAA"
corporate debt securities for a series of average lives.
2-10
<PAGE>
<TABLE>
<CAPTION>
2-YEAR 3-YEAR 5-YEAR 7-YEAR 10-YEAR
------ ------ ------ ------ -------
<S> <C> <C> <C> <C> <C>
MANUFACTURED
HOUSING ABS +39 bps. +39 bps. +52 bps. +62 bps. +85 bps.
INDUSTRIAL "AAA" +15-20 bps. +20-25 bps. +25-30 bps. +30-35 bps. +35-40 bps.
</TABLE>
Source: Morgan Stanley & Co., as of March 7, 1997.
Note: "bps." equals basis points spread over U.S. Treasury Notes
B APPLICATION OF ASSET BACKED FINANCE TO THE RESTRUCTURING OF
-----------------------------------------------------------
THE ELECTRIC UTILITY INDUSTRY
-----------------------------
As is discussed in detail in Chapter 3, PG&E, based on the passage of
Assembly Bill 1890 (AB 1890), proposes to securitize the property right to a
consumption-based charge, called the Fixed Transition Amount (FTA) charge,
levied on residential and small commercial customers as a means of
facilitating its transition to a competitive generation market. The property
right created by AB 1890 is called Transition Property. The securitization of
the Transition Property will enable PG&E to recover a portion of its
transition costs and provide a 10 percent rate reduction to residential and
small commercial customers.
The rating of the securitization of the Transition Property will be
based primarily on an analysis of the credit risk associated with customers'
ability to pay the FTA charge and the ability of PG&E to accurately forecast
the expected consumption of its residential and small commercial customer
base. These factors, along with other considerations, determine the ability of
the FTA revenues to meet the scheduled payment requirements. As the credit
quality of the FTA cash flow stream and PG&E's ability to forecast consumption
over the term of the securitization are most likely less than "AAA," credit
enhancement must be added to the securitization to ensure that the transaction
will receive the highest possible rating.
Credit enhancement for the securitization is expected to be comprised
of the statutory true-up mechanism and a small overcollateralization amount.
The true-up
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<PAGE>
mechanism will enable PG&E to revise its projected consumption schedule and
adjust the FTA charge to help ensure full and timely payment of debt
service.
The overcollateralization amount will be sized by the rating agencies
based on the application of extreme assumptions as to PG&E's expected level
of delinquencies, losses and usage volatility. The overcollateralization
amount will represent the difference between the aggregate principal amount
expected to be collected through the FTA charge, and the principal amount
of RRBs to be issued. Investors are protected, or credit enhanced, in the
event that less than the entire principal amount, absent
overcollateralization, would have been collected.
Investor interest is expected to be very strong for this product due
to the strong credit characteristics and the stability of the cash flow
stream of the security. Investors are persistently looking for alternative
ABS investments as a means of achieving incremental yield and diversifying
their ABS portfolios. As the RRBs are anticipated to be divided into
various tranches or classes representing average lives ranging from three
months to 10 years, investor interest is expected to come from all
investment sectors. RRB investor participants are expected to include money
market funds, domestic and international banks, institutional and retail
trust funds, money managers, investment advisors, pension funds, insurance
companies, securities lenders and corporate cash managers. Traditional
utility first mortgage bond investors are also expected to be attracted to
this product as it enables them to buy higher rated utility-related
securities.
In preliminary meetings with potential RRB investors, investors have
expressed concern about the risk of AB 1890 being overturned or abolished
in the future due to fundamental changes in the industry or due to
political considerations. Investors are uncertain how to quantify or
evaluate this type of risk since it is novel to the ABS market. Obtaining a
bankruptcy "true sale" opinion from legal counsel and a high credit rating
from rating agencies will help allay potential concerns of investors.
Multiple
2-12
<PAGE>
classes of securities with varying average lives may also serve to mitigate
this concern for certain investors by allocating it primarily to the longer
average life classes.
It is preferable that the RRBs, related to each California utility, be
issued in one or two large, liquid transaction(s) rather than in multiple
issues over several years, in order to minimize the all-in cost of the
transaction. The ABS market has readily absorbed large size transactions
(as noted in the table on page 2-9) as such issues offer investors
substantial liquidity. Large size transactions issued within a short period
of time would also generate the greatest investor interest and momentum for
the transaction and maximize the impact of any initial investor road show
and investor meetings occurring prior to the transaction's launch into the
ABS market.
While the transaction would be issued in one or two offering(s), the
offering(s) would likely be split into multiple classes of various average
lives in order to attract the greatest breadth of investor demand. Each of
the classes would be substantial in size to offer liquidity to investors.
Different types of investors would be expected to be attracted to the
different classes.
This concentrated issuance approach will also save customers
repetitive fixed transaction expenses such as rating agency fees, trustee
fees, accounting costs, and printing costs, as well as minimize legal costs
that would be incurred with small offerings over multiple years.
2-13
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
CHAPTER 3
TRANSACTION OVERVIEW
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
CHAPTER 3
TRANSACTION OVERVIEW
A. INTRODUCTION
------------
The purpose of this chapter is to present an overview of the proposed
financing transaction and the considerations that determine the proposed
transaction structure. The remainder of this chapter is organized as
follows:
B. Overview of Assembly Bill 1890 (AB 1890)
C. Proposed Transaction Structure
D. Factors Determining the Proposed Transaction Structure
E. Servicing the Rate Reduction Bonds (RRBs)
F. Timing and Sizing of the Proposed Transaction
G. RRB Characteristics
H. Transaction Costs and Use of Proceeds
B. OVERVIEW OF AB 1890
-------------------
On September 23, 1996, Governor Wilson signed into law AB 1890, a
comprehensive electric industry restructuring bill which had been unanimously
approved by the California State Legislature. Among other things, AB 1890
authorizes electric utilities to recover a portion of their transition costs
(Financed Transition Costs) through the issuance of a new type of asset
backed security, known as RRBs (Public Utilities (P.U.) Code (S)840(e)). AB
1890 generally defines transition costs as the costs and categories of costs
for generation-related assets and obligations, consisting of generation
facilities, generation-related regulatory assets, nuclear settlements, and
power purchase contracts, that may become uneconomic as a result of a
competitive generation market (P.U. Code (S)840(b)).
3-1
<PAGE>
Conditioned upon the issuance of RRBs, AB 1890 requires utilities to
reduce rates for residential and small commercial customers by at least 10
percent beginning on January 1, 1998, and continuing through the earlier of
when PG&E recovers its transition costs except for those allowed a longer
recovery period, or March 31, 2002 (the rate freeze period) (P.U. Code
(S)330(w) and 367(a))./1/ PG&E is able to deliver the 10 percent rate
reduction by issuing RRBs at an interest rate that is lower than the otherwise
authorized rate of return on the Financed Transition Costs and by extending
the debt service on the RRBs beyond the authorized transition cost recovery
period.
AB 1890 requires residential and small commercial customers to fund
payments of the principal, interest and related costs on the RRBs through
separate, non-bypassable charges called Fixed Transition Amounts (FTAs). FTAs
are generally defined in AB 1890 as non-bypassable rates and other charges
that are authorized by the Commission in a Financing Order to recover Financed
Transition Costs and the costs of providing, recovering, financing or
refinancing transition costs, including the costs of issuing, servicing, and
retiring RRBs (P.U. Code (S)840(d)). Residential and small commercial
customers will pay the FTAs as a component of their monthly bill (FTA charge).
The FTA charge will be a usage based, cents-per-kilowatt hour charge.
AB 1890 designates as an irrevocable property right the future non-
bypassable FTA revenues the utilities will collect from residential and small
commercial customers. This property right, defined in AB 1890 as Transition
Property, includes the right, title and interest to all revenues, collections,
claims, payments, money or proceeds arising from FTAs that are the subject of
a Financing Order issued by the Commission (P.U. Code (S)840(g)). Upon the
issuance of RRBs, the right to recover FTAs is
- -------------------
/1/ The determination of the size of the RRBs assumes that the rate freeze
period will end on March 31, 2002, which under AB 1890 is the last possible
day the rate freeze period can end (see Chapter 4). The ratemaking
mechanism described in Chapter 5 addresses the effect of an earlier end to
the rate freeze period.
3-2
<PAGE>
irrevocable and cannot be rescinded, altered or amended by either the
Commission or the State of California (P.U. Code (S)841(c)).
AB 1890 provides for the RRBs to be issued through the California
Infrastructure and Economic Development Bank (Infrastructure Bank), or
another financing entity (Issuer) affiliated with, or approved by the
Infrastructure Bank (P.U. Code (S)840(b)). Prior to issuance, the utilities
must submit an application to the Infrastructure Bank for approval of the
Issuer and the terms and conditions of the RRBs.
AB 1890 requires each utility to apply to the Commission for a Financing
Order, no later than June 1, 1997, for a determination of the amount of
transition costs to be financed by RRBs and the establishment of a procedure
for the periodic adjustment to FTAs. The periodic adjustment (true-up
mechanism) will ensure RRB investors that the FTA charge can be increased or
decreased to adjust for any variations in actual RRB principal amortization
versus scheduled amortization. The Commission is required to issue a
decision on the Financing Order within 120 days of the application
submission (P.U. Code (S)841(e)). The Financing Order will become effective
only after PG&E files its written consent to all terms and conditions of the
Financing Order (P.U. Code (S)841(b)).
C. PROPOSED TRANSACTION STRUCTURE
------------------------------
PG&E proposes the following structure for the issuance of RRBs; however,
the exact structure will be finally determined by the Infrastructure Bank
when the RRBs are issued:
1. PG&E will form a Special Purpose Entity (SPE), wholly-owned and organized
by PG&E. PG&E will contribute equity to the SPE in an amount equal to
approximately 0.50 percent of the total RRB principal amount, and will,
in the form
3-3
<PAGE>
of a sale, transfer title to the Transition Property (the right to future
FTA revenues collected from residential and small commercial customers)
to the SPE./2/
2. In order to fund the acquisition of the Transition Property, the SPE will
issue debt securities to the Issuer. The Transition Property and the SPE
equity will be used as collateral to secure the SPE debt securities.
3. The Issuer will issue RRBs to investors in the form of notes or
certificates. The RRBs will be secured by the debt of the SPE, which will
mirror the terms and conditions of the RRBs. The proceeds from the
issuance of the RRBs will be transferred from the Issuer to the SPE. The
SPE will then pay the proceeds to PG&E in exchange for the Transition
Property.
The following schematic illustrates the proposed transaction:
[DESCRIPTION TO COME]
D. FACTORS DETERMINING THE PROPOSED TRANSACTION STRUCTURE
------------------------------------------------------
The proposed transaction structure is necessary to issue the lowest-cost,
highest-rated RRBs possible. The transaction has been structured to address
the following issues:
- --------------------------
/2/ PG&E requests that the Commission find that, upon the sale by PG&E of the
Transition Property to the SPE, (1) such SPE shall have all of the rights
originally held by PG&E with respect to such Transition Property,
including, without limitation, the right to exercise any and all rights
and remedies to collect any amounts payable by any customer in respect of
such Transition Property, notwithstanding any objection or direction to
the contrary by PG&E, and (2) any payment by any customer to such SPE
shall discharge the customers' obligation in respect of such Transition
Property to the extent such payment notwithstanding any objection or
direction to the contrary by PG&E. This finding reinforces that Transition
Property is a separately identifiable, transferrable asset.
3-4
<PAGE>
1. RRB Credit Rating Issues
------------------------
Satisfactory regulatory approvals will help ensure that the RRBs receive
the highest possible rating from at least two national credit rating
agencies. The credit analysis of asset backed securities centers on the
extent to which the structure of the transaction isolates the assets from
the credit risks of the originating company and on the credit quality of the
assets themselves. The ratings will be based on several factors including:
(1) the bankruptcy opinion of counsel regarding the transfer of the
Transition Property from PG&E to the SPE, (2) the FTA true-up mechanism, (3)
credit enhancement, (4) the analysis of PG&E's ability to accurately
forecast energy usage and the credit risks associated with residential and
small commercial customers, (5) the risks associated with currently unknown
third party servicers collecting a portion of the FTA charge, and (6) the
legislative and regulatory risks associated with the transaction.
In order to obtain the desired credit rating on the RRBs, PG&E must
provide a satisfactory opinion of counsel, at the time the RRBs are issued,
establishing that the transfer of the Transition Property from PG&E to the
SPE constitutes a "true sale" for bankruptcy purposes and that PG&E and the
SPE would not be substantively consolidated for bankruptcy purposes. The
"true sale" transaction between PG&E and the SPE provides the rating
agencies assurance that, in the event of a PG&E bankruptcy, the Transition
Property and the related revenues collected under the FTA charge would not
be part of the bankruptcy estate of PG&E and, thus, would be unavailable for
the satisfaction of PG&E's creditors. Instead, this revenue stream would
continue to be collected for the SPE, which has pledged it to pay debt
service on its securities to the Issuer, which in turn has pledged these
debt securities to pay debt service on the RRBs to investors.
PG&E expects to work with the Infrastructure Bank to structure the RRB
transaction so that a satisfactory "true sale" opinion can be delivered to
the rating
3-5
<PAGE>
agencies. Among other things, the "true-sale" structure will involve the
following: (1) to the extent feasible, a line item on the utility bill will
be established to provide notice that the customer bill amounts attributable
to the FTA charge are separate and distinct from the revenues of the
utility; (2) PG&E, acting as servicer of the RRBs on behalf of the SPE, will
be paid a servicing fee which represents a fair market price for these
services since PG&E has no economic interest in the FTA revenues (Transition
Property) and is merely a servicer being paid a market rate, as measured by
the fees paid to other servicers in this type of transaction; furthermore,
the fee must be adequate to attract a substitute servicer in the event PG&E
fails to satisfactorily perform as servicer; and (3) consistent with the
SPE's ownership of the Transition Property, the customers will have the
legal right to pay the SPE directly, and the SPE will have the corresponding
legal right to sue customers for nonpayment of the FTA charges./3/
Thus, the SPE and its assets will be considered "bankruptcy-remote."
"Bankruptcy-remote" means that, (1) in the event of a bankruptcy of PG&E,
the SPE's assets should be separate and not subject to the claims of PG&E's
creditors and, (2) since the only activity of the SPE is related to the
issuance of RRBs in connection with PG&E's Transition Property and the SPE
is structured to avoid voluntary declaration of bankruptcy, the possibility
of an SPE bankruptcy is diminimus.
AB 1890 provides for an FTA true-up mechanism to be implemented by
the Commission at least annually (P.U. Code (S)841(e)). This true-up
mechanism will allow PG&E to adjust the FTA charge to account for
variations in actual FTA collections from those originally forecast, which
cause the actual amortization of the
- -----------------------------------------
/3/ To further enhance the credit quality, PG&E requests that, in the event of
a default by PG&E in payment of the FTA charge to the SPE, the Commission,
upon application by the Bond Trustee, shall order the sequestration and
payment to the SPE or such other party of revenues arising with respect to
Transition Property.
3-6
<PAGE>
RRBs to diverge from the scheduled amortization. Such variations may be due
to, among other things, deficiencies due to reduction in usage from
projections, failure of customers to pay amounts owed, and failure of PG&E
or third-party servicers to remit the full amount of their FTA collections.
The design, frequency and ensured regulatory implementation of this true-up
mechanism are critical to the rating agencies in their determination of the
reliability and adequacy of debt service payments. The authorized frequency
and timely Commission review and approval of true-up filings will also be
important factors in determining how much additional credit enhancement the
rating agencies will require.
Additional credit enhancement is expected to be in the form of
overcollateralization. As discussed in Chapter 2, overcollateralization
further ensures that bondholders will receive all principal and interest
due them by requiring the Bonds to be secured with an asset, in this case
Transition Property, the value of which is in excess of the amount of the
total principal amount of the Bonds. The overcollateralization will be
sized by the rating agencies, based on the amount of principal and interest
which would otherwise remain unpaid on the expected maturity date under the
rating agencies' worst case scenario (stress analysis). Any
overcollateralization that is collected as part of the FTA charge, in
excess of total debt service, will be the property of the SPE.
In order to determine the amount of credit enhancement, the rating
agencies will also analyze PG&E's ability to accurately forecast the
expected energy usage by residential and small commercial customers by
looking at historic data on forecasted and actual usage. The rating
agencies are expected to apply a wide range of assumptions on
uncollectibles and energy usage and the effectiveness of the true-up
mechanism to assess how vulnerable FTA revenues are to changes in
assumptions. This stress analysis is important, and the authorized
frequency and prompt
3-7
<PAGE>
implementation of the true-up mechanism are critical in reassuring the
rating agencies that the RRB debt service will be paid.
The rating agencies are also very focused on the financial strength
and the billing and collecting experience of the servicer. While PG&E will
be the initial servicer, pursuant to the Commission's cost separation
proceeding in the industry restructuring process, it is possible that
currently unknown third parties will be billing and collecting payments
from a portion of the customers that will pay the FTA charge. In order to
ensure that the RRBs' credit rating is not adversely affected, PG&E
requests that the Commission approve the following principles that would be
applied by the Commission in establishing minimum standards for third-party
servicers that may bill and collect the FTA charge from residential and
small commercial customers:
a. Regardless of who is responsible for performing the billing and
collection functions, residential and small commercial customers will
continue to be responsible for FTA charges in accordance AB 1890.
Residential and small commercial customers must always be responsible for
paying the FTA charge, regardless of who actually bills and collects that
charge from those customers. This clear and continuing obligation cannot be
blurred as a result of a third-party servicer billing and collecting the
FTA charge and then paying its aggregated FTA collections to the utility.
b. If a third-party servicer meters and bills for the FTA charges, the
utility must have access to information regarding kilowatt-hour usage
and billings to provide proper reporting as primary servicer for RRBs.
Irrespective of who performs the metering and billing functions, PG&E must
have access to information regarding customer usage and billings in order
to properly report FTA revenues to the Bond Trustee as required under its
Servicing Agreement.
3-8
<PAGE>
c. Appropriate shut-off policies must be maintained to minimize investors'
credit risk in the case of non-payment of the FTA by individual
customers.
Current shut-off policies must be maintained to allow shut-off by the
utility or third-party servicer in the case of non-payment of the FTA,
regardless of who is responsible for the billing and collecting FTAs.
d. Appropriate standards, procedures and credit policies must be in place
to ensure that the collection of FTA charges by a third-party servicer
does not result in an increased risk to investors. Such standards
should be consistent with existing rating agency standards governing
billing, collecting and reporting for servicers in similar asset backed
securities transactions.
Rating agencies and investors will see an additional layer of risk if
third-party servicers with less than investment grade credit ratings,
collect and hold FTA charges prior to remittance to the utility. To ensure
that the risk associated with a third-party servicer default is mitigated,
rating agencies will want to see that appropriate credit policies be in
place. For example, if a third-party servicer is not rated, or rated below
investment grade, the rating agencies may require that all customer
collections be remitted within 48 hours of receipt or alternatively,
security deposits, letters of credit, or other forms of credit enhancement
may be required. Furthermore, third-party servicers must have systems
capabilities and procedures in place that are necessary to promptly bill,
collect and report FTA charges.
e. In the event of a third-party servicer default, billing and collecting
responsibilities must be promptly transferred to another party to
minimize losses.
In the event that a third-party servicer defaults on its timely payments to
the utility of FTA collections, the rating agencies will desire prompt
action to replace the defaulting servicer to assure FTA charges paid by
customers can be passed on to investors.
3-9
<PAGE>
The broad policies outlined above are only a subset of those likely to
be addressed in the Commission's Direct Access and Ratesetting proceedings.
PG&E does not desire to preempt a full discussion in those proceedings.
However, these issues are important for achieving the highest possible Bond
rating and the minimum ratepayer cost associated with the RRB issuance. As
a result, PG&E requests that the Commission indicate its intent to set
appropriate procedures for third-party servicers by approving the general
guidelines described above.
Additional factors the rating agencies will consider when rating the
RRBs are the legislative risks associated with AB 1890 including the risk
that AB 1890 could be overturned or abolished in the future. Since AB 1890
was unanimously passed by the California Legislature, and it results in
economic benefits to residential and small commercial ratepayers, PG&E
expects the rating agencies to conclude that the legislative risk
associated with the transaction should not affect the Bonds' rating.
The rating agencies will also analyze the regulatory risk associated
with the transaction. As stated in AB 1890, the Financing Orders and the
FTAs shall be irrevocable, and the Commission shall not have authority
either by rescinding, altering or amending the Financing Order, to revalue
the costs of providing, recovering, financing, or refinancing the
transition costs (P.U. Code (S)841(c)). Nevertheless, the quality of the
Financing Order, particularly with regard to the initial tariff
implementation, the true-up mechanism and requirements for third-party
servicers, will be carefully reviewed by the rating agencies when they
determine the rating of the Bonds.
2. Tax Issues
----------
PG&E expects that the transfer of Transition Property to the SPE and
the issuance of RRBs will not cause the current recognition of taxable
income for the following reasons: (1) the transfer of the FTA charge to the
SPE has no federal income tax consequences because the SPE and the utility
are within the single
3-10
<PAGE>
PG&E tax entity, (2) the SPE's issuance of debt securities will be treated
as secured debt for tax purposes, and (3) because of the characteristics of
the FTA charge, no income associated with the FTA charge will be recognized
until electric services are provided to PG&E's customers paying the FTA
charge. The contribution from PG&E to the SPE of a small amount of equity,
not expected to exceed 0.50 percent of the RRB principal amount, further
reinforces the Company's tax position that the transaction should be
treated as debt for tax purposes.
PG&E is very confident that these conclusions are sound. However, due to
the size of this transaction, PG&E and the other California electric
utilities have submitted ruling requests to the Internal Revenue Service
(IRS) seeking confirmation. PG&E's request asks the IRS to rule on two
issues: (1) whether the securities issued by the SPE are considered debt
for federal income tax purposes, and (2) whether income will accrue on the
Transition Property only when the related electric services are provided to
consumers.
The request was submitted to the IRS on February 26, 1997. PG&E does not
expect to receive a formal response for several months, although it may
receive information on an informal basis sooner. In discussions with the
IRS, the Company has stressed the importance of the June 1, 1997 deadline
for submitting a restructuring proposal to the Commission. PG&E is
optimistic that, if the IRS agrees to rule, the IRS will give the requested
ruling expedited consideration.
If the IRS declines to rule or rules adversely, PG&E will first
reevaluate the transaction to determine if modifications can be made which
do not result in current taxation and which do not significantly undermine
the benefits of the transaction. If this cannot be done, PG&E would seek to
modify this application with the Commission.
3-11
<PAGE>
3. Accounting Issues
-----------------
PG&E and the other California electric utilities submitted a letter to
the Securities and Exchange Commission (SEC) requesting that, for
financial reporting purposes, the transfer of the Transition Property to
the SPE be treated as a sale. The SEC denied the utilities' request and,
as a result, the SPE's debt securities (which mirror the RRBs) will be
recorded as debt on the utilities' balance sheets. Showing the SPE debt
securities on PG&E's balance sheet is not expected to have an impact on
the credit rating of PG&E's existing securities since the SPE debt
securities will be non-recourse to PG&E. PG&E will add a footnote to its
financial statements disclosing that the RRBs are secured solely by
Transition Property and SPE equity, that RRB investors have no recourse
to any assets or revenues of PG&E, and that, conversely, PG&E and its
creditors have no claim to the Transition Property.
E. SERVICING THE RRBs
------------------
PG&E intends to act as servicer for the RRBs to the extent it retains the
right to bill and collect the FTA charges from residential and small
commercial customers. In its capacity as servicer, PG&E will be responsible
for reading customer meters and billing and collecting the FTA charge. PG&E
is expected to remit estimated FTA collections to date, on behalf of the
SPE, to the RRB Indenture Bond Trustee Bank (Bond Trustee). The Bond Trustee
is responsible for making quarterly debt service payments to RRB investors
and paying other ongoing costs associated with the transaction. These
ongoing costs include the cost of servicing the RRBs, described in further
detail below, Bond Trustee fees and other administrative costs. Bond Trustee
fees and other administrative costs (excluding servicing fees) are expected
to be approximately $60,000 per year.
3-12
<PAGE>
The following schematic illustrates the servicing cashflows:
The omitted graphic reflects the flow of the Customer Payment including FTA
Charge from Residential and Small Commercial Customers to PG&E (as Servicer),
the flow of the FTA charge on Behalf of the SPE to the Bond Trustee, and the
flow of Debt Service to the Investors, and in the other direction the flow of
the Customer Bill including FTA charge from PG&E to the Residential and Small
Commercial Customers.
The FTA charge will be comprised of the following components: (1) scheduled
debt service on the RRBs, (2) servicing fees, (3) Bond Trustee fees, (4)
overcollateralization, (5) allowance for uncollectibles, and (6) other ongoing
expenses.
PG&E will also be responsible for filing an advice letter with the
Commission, at least annually, to adjust the FTA charge, to the extent that
actual debt service payments vary from scheduled debt service payments, and to
reflect revised annual usage forecasts.
The FTA charge is expected to appear as a separate line item on the monthly
bill of residential and small commercial customers beginning in January 1998.
As mentioned above, PG&E will be responsible for reading customer meters,
billing, collecting and remitting the FTA charge to the Bond Trustee. PG&E has
sold its right to FTA revenues and is legally obligated to remit 100 percent of
FTA collections to the Bond Trustee net of PG&E's servicing compensation. PG&E
plans to remit estimated FTA collections to date to the Bond Trustee once a
month, pending rating agency approval. If PG&E's or other servicer's short-
term credit rating falls below "A-1," "P-1," "F-1," the rating agencies are
expected to require FTA remittances to the Bond Trustee within two days of
receipt to avoid an adverse impact on the RRBs' credit rating. The rating
agencies may also require the servicer to provide additional credit
enhancement, such as a letter of credit, to maintain the RRBs' rating.
3-13
<PAGE>
As servicer, PG&E will receive the FTA collections daily and will commingle
FTA collections with other customer payments until the monthly remittance date
to the Bond Trustee. Any benefits that result from PG&E having use of FTA
collections between remittance dates will be credited to residential and small
commercial customers as described in Chapter 5.
PG&E will prepare a monthly servicing report for the Bond Trustee detailing
the estimated FTA collections during each month over the life of the RRBs.
Estimated FTA collections will be based on an analysis of customer payment
patterns.
Six months after each monthly billing period, PG&E will compare actual FTA
collections to the estimated FTA collections that have been remitted over six
months to the Bond Trustee. The six-month lag between the first remittance of
estimated FTA collections and the final determination of actual FTA cash
collections allows for the collection process to take its course and is
consistent with PG&E's practice of waiting six months after the initial billing
before writing off unpaid customer bills.
The Bond Trustee will have a legal right to only the amount of actual FTA
cash collections. Variance (positive or negative) between the amounts
previously remitted based on estimated collections and the amount calculated to
have been actually received based on final write-offs will be netted against
the following month's remittance. Amounts collected that represent partial
payments of a customer's bill will be allocated between the Bond Trustee and
PG&E based on the ratio of the portion of the billed amount allocated for the
FTA charge to the total billed amount. This allocation is an important
bankruptcy consideration in determining the "true-sale" nature of the
transaction.
The Bond Trustee will retain all FTA collections until it makes scheduled
principal and interest payments and all servicing fees and ongoing expense
payments to the appropriate parties. These distributions are expected to be
made on a quarterly basis. The Bond Trustee will hold all FTA collections
received from PG&E between the
3-14
<PAGE>
remittance date and distribution date in a collection account. The Bond Trustee
will invest the funds in the collection account in investment grade short-term
securities which mature on or before the next distribution date.
Interest earned on the investments in the collection account is expected to
be paid to the SPE, except in the unlikely event that they are needed to pay
interest on, or, at maturity, principal of, the RRBs due to FTA collection
shortfalls.
PG&E expects that after the rate freeze period, its rates charged to
residential and small commercial customers will be reduced periodically to
reflect (1) distributions by the SPE to PG&E, and (2) any increase in the value
of PG&E's ownership interest in the SPE./4/
As servicer, PG&E will be responsible for filing with the Commission for any
necessary FTA charge adjustments. PG&E expects to file for adjustments at least
annually. PG&E is also requesting authorization to file for adjustments, as
often as quarterly, in the event that actual quarterly debt service payments
vary from scheduled debt service payments by more than a specified percent, as
determined necessary for the highest possible rating. Either an increase or
decrease in the FTA charge would be requested if the actual debt service
payments were less than or greater than what was scheduled, respectively. The
true-up mechanism is described in detail in Chapter 6.
As previously mentioned, the SPE must pay PG&E a servicing fee to be
collected in the FTA charge that constitutes a fair and reasonable price in
order to preserve the "true sale" bankruptcy opinion. As discussed in Chapter
2, annual servicing fees for asset securitization transactions can range from
0.50 percent to 3.50 percent. PG&E expects
- -------------------------------------------
/4/ Upon formation of the SPE, PG&E expects that the value of its interest in
the SPE will be equal to the amount of equity contributed by PG&E to the SPE
as capital. Any undistributed amount of investment earnings or
overcollateralization actually collected as part of the FTA charge is
expected to result in a corresponding increase in the value of PG&E's
ownership interest in the SPE (investment earnings and overcollateralization
that are distributed to PG&E by the SPE, or result in an increase in PG&E's
ownership interest in the SPE, are referred to as investment earnings and
overcollateralization, respectively).
3-15
<PAGE>
to charge an annual servicing fee of 1.50-2.00 percent of the original RRB
principal amount. PG&E will adjust its future rates to residential and small
commercial customers after the rate freeze period to credit the servicing
fee, net of any recorded incremental servicing costs, as described in Chapter
5. PG&E expects incremental servicing costs to be approximately $50,000 per
year.
In the event that PG&E fails to satisfactorily perform its servicing
functions, as set forth in the Servicing Agreement, or is required to
discontinue its billing and collecting functions, an alternate servicer
acceptable to the Bond Trustee will replace PG&E and assume such billing and
collecting functions. As discussed above and in Chapter 2, the credit quality
and expertise in performing servicing functions are important considerations
when appointing an alternate servicer.
If PG&E no longer performs servicing functions, the servicing fee will be
paid directly to the alternate servicer and PG&E's future rates would not be
adjusted to reflect the amount of the servicing fee.
F. TIMING AND SIZING OF THE PROPOSED TRANSACTION
---------------------------------------------
Prior to issuance, PG&E is required to submit an application to the
Infrastructure Bank for approval of the terms and conditions of the RRBs. The
Infrastructure Bank application is composed of two parts. The first part
consists of a general description of the proposed transaction and is expected
to be submitted concurrently with this filing. The second part is a more
detailed description of the proposed transaction and is expected to be
completed late in the third quarter of 1997. The Infrastructure Bank is
expected to authorize the issuance of RRBs after the second part of the
application has been submitted and the Commission has issued its final
decision in this proceeding.
PG&E currently anticipates that it will make a request to the Issuer and
the California State Treasurer's Office that the RRBs be issued on one or
more dates in the fourth quarter of 1997. The State Treasurer is required to
be the agent for sale of the RRBs. In this capacity, the State Treasurer, in
conjunction with the Infrastructure Bank,
3-16
<PAGE>
will review and approve all of the terms and conditions of the RRBs to ensure
that the issuance costs are reasonable and that the RRBs are prudently priced
given the condition of the financial markets at the time of issuance.
To allow the RRBs to be issued in time to provide for the 10 percent rate
reduction on January 1, 1998, PG&E requests authorization for the initial FTA
charge to be effective prior to January 1, 1998. Specifically, PG&E proposes
to file an advice letter with the Commission no less than five business days
prior to the close of the sale of the RRBs and requests that the advice
letter be approved prior to the close of the sale. The advice letter will
include the final issuing details and request that the initial FTA charge be
set based on the actual amount and price of the RRBs issued./5/ The initial
FTA charge must be effective before the related RRB sale can close because it
is the Transition Property which is the basis of this asset securitization.
PG&E proposes to follow the same procedure for any FTA charge adjustments
that are necessary to account for additional RRB issuance on later dates.
PG&E expects the Issuer to sell up to a maximum of $3.5 billion of RRBs.
The final size of the issuance will be determined by the amount of RRBs
necessary to support a 10 percent rate reduction for residential and small
commercial customers beginning on January 1, 1998, and continuing through the
end of the rate freeze period. The sizing model which calculates the amount
of RRBs necessary to support the 10 percent rate reduction is discussed in
detail in Chapter 4.
- -----------------------
/5/ PG&E requests that the Commission find that the Transition Property
identified in the Issuance Advice Letter associated with the Financing
Order shall include, without limitation, (1) the right, title and interest
in and to the FTA charge set forth in such Advice Letter, as adjusted from
time to time, (2) the right to be paid the total amount set forth in such
Advice Letter, (3) the right, title and interest in and to all revenues,
collections, claims, payments, money, or proceeds arising from such FTA
charge, and (4) the right, title and interest in and to all rights to
obtain adjustments to such FTA charge under the true-up mechanism. This
finding will reinforce the relationship between FTA charges and Transition
Property.
3-17
<PAGE>
If, as a result of sales growth, the initial size of the RRB transaction
is not sufficient to fund the 10 percent rate reduction, PG&E will arrange
for the issuance of additional RRBs. This is further discussed in Chapter 5.
As previously mentioned, PG&E is able to provide the 10 percent rate
reduction during the rate freeze period by having the RRBs issued at an
interest rate lower than the authorized rate of return on the Financed
Transition Costs and by recovering the RRB debt service beyond the authorized
transition cost recovery period.
Residential and small commercial ratepayer benefits resulting from the
issuance of RRBs include the 10 percent rate reduction and estimated net
present value savings of approximately $470 million based on an issuance size
of $3.1 billion. The net present value savings are calculated based on the
difference between (1) the cash flow stream that these customers will pay
with the RRBs and the 10 percent rate reduction, and (2) the cash flow stream
if there were no RRBs and no 10 percent rate reduction. The assumed ratepayer
discount rate, or time value of money, is 10 percent. These ratepayer
benefits are larger than the projections made in conjunction with the
legislative evaluation and passage of AB 1890.
G. RRB CHARACTERISTICS
-------------------
The RRBs are expected to be in the form of notes or certificates with
multiple expected final maturities ranging from three months to 10 years and
legal final maturities ranging from one to 13 years to allow for delays in
scheduled principal payments. The structure and maturity dates will be
determined at the time the RRBs are priced, to result in the lowest debt cost
while reaching a wide investor base. Interest rates will be fixed or floating
as determined by the Infrastructure Bank or State Treasurer at the time of
issuance to provide the lowest all-in cost of Bonds. Any floating rate
exposure will be mitigated with swaps or other interest rate risk management
instruments as approved by the Infrastructure Bank or State Treasurer. The
debt service in the FTA charges would
3-18
<PAGE>
be based on the resulting fixed interest rate so customers would not have any
floating rate risk.
PG&E proposes to amortize the RRBs based on level principal payments. This
is based on rating agency and assumed ratepayer preference for an FTA charge
which declines over the life of the RRBs.
Each separate RRB note or certificate will be priced based on its average
life, determined by the projected principal amortization schedule at the time
of issuance. Each RRB tranche will be priced at a basis point spread over the
United States Treasury Note with a comparable average life.
H. TRANSACTION COSTS AND USE OF PROCEEDS
-------------------------------------
PG&E estimates that the costs associated with the proposed transaction,
excluding servicing fees and other ongoing costs, will be approximately $25
million. These costs include investment banking fees, legal fees, rating
agency fees, SEC registration fees, accounting fees, Bond Trustee fees,
Infrastructure Bank fees, printing fees, and miscellaneous fees. PG&E is not
including any of its labor costs as transaction costs. As provided for in
P.U. Code (S)840(d), these transaction costs will be financed and are
included in the RRB sizing calculations further discussed in Chapter 4. The
transaction costs are provided as estimates; the actual costs will be
approved by the Infrastructure Bank or State Treasurer's office. A detailed
break-out of the estimated transaction costs is provided in Attachment 3A.
These fees are appropriate in light of the extreme complexity of this
transaction, which is the first of its kind in the marketplace, and the long
lead time necessary to develop and bring this transaction to a close. These
fees are expected to be less than one percent of the RRB amount, in line with
the fee percentage in other complex utility securities such as pollution
control bonds, project financings and leveraged preferred stock issues.
3-19
<PAGE>
PG&E intends to use the net proceeds received from the sale of RRBs to
reduce outstanding utility debt and equity in proportions as close as
practicable to those of PG&E's existing capital structure, consistent with the
capital structure condition established by the Commission in the PG&E Holding
Company decision.
It is possible that certain costs may be incurred to retire debt issues
prior to their maturity dates. However, it would be inappropriate to separate
changes in the embedded cost of debt, the cost of retirements and the avoided
cost of additional financings due solely to the RRBs. In addition to the impact
on the embedded cost of debt which results from calling debt issues prior to
their maturity dates, a significant amount of debt reduction will occur through
scheduled maturities. These maturities, which generally consist of lower coupon
debt, would impact the embedded cost of debt regardless of the RRB transaction.
Any increase or decrease in PG&E's embedded cost of debt will be addressed
in the Company's Cost of Capital proceeding and will be reflected in rates for
all customer classes.
3-20
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
ESTIMATED RRB TRANSACTION COSTS
ATTACHMENT 3A
<TABLE>
<CAPTION>
Line Line
No. No.
------- ---------
<C> <S> <C> <C>
1 Underwriter Fees $19,375,000 1
2 Legal Fees 2,700,000 2
3 SEC Registration Fees 950,000 3
4 Rating Agency Fees 500,000 4
5 Accounting Fees 300,000 5
6 Infrastructure Bank Fees 200,000 6
7 Miscellaneous 975,000 7
-----------
8 Total $25,000,000 8
</TABLE>
Note: Cost estimates based on an issue size of $3.1 billion.
3-21
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
CHAPTER 4
SIZE OF THE RATE REDUCTION BOND ISSUANCE
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
CHAPTER 4
SIZING OF THE RATE REDUCTION BOND ISSUANCE
A. INTRODUCTION
------------
The purpose of this chapter is to present the revenue requirement
calculation necessary to determine the size of the RRB issuance, and to
present the customer benefits derived from the 10 percent rate reduction
during the rate freeze period/1/ and the issuance of the RRBs. The remainder
of this chapter is organized as follows:
B. Sizing of the RRB issuance:
1. Overview
--------
a. Target revenue reductions
b. Gross avoided revenue requirements
c. RRB debt service revenue requirements
d. Net change in revenue requirements
2. Customer benefits
-----------------
B. SIZING OF THE RRB ISSUANCE
--------------------------
1. Overview
--------
This section provides a conceptual overview of the model PG&E uses
to determine the size of the RRB issuance. Appendix A to this testimony
contains a line-by-line explanation of PG&E's sizing model. In summary,
PG&E determines the size of the RRBs by solving for an amount of
transition costs that must be financed (Financed Transition Costs) with
the RRBs in order to achieve a 10 percent rate reduction for residential
and small commercial customers during the rate freeze
- ------------------
/1/ For purposes of sizing the RRBs, the rate freeze period is assumed to
begin on January 1, 1998 and continue through March 31, 2002, the latest
date permitted under AB 1890 for the end of the rate freeze period.
4-1
<PAGE>
period. The amount of Financed Transition Costs must provide revenue
requirement savings during the rate freeze period sufficient to offset
both the 10 percent rate reduction and the rate freeze period FTA charge
on the RRBs (see Figure 4-1).
a. Target Revenue Reductions
-------------------------
Although the amount of the RRB issuance is sized in order to
achieve a 10 percent rate reduction, the sizing is based on
calculations of dollar revenue requirements. Therefore, the first
step in determining the size of the RRBs is to convert the target 10
percent rate reduction into a target revenue requirement reduction.
This first step is fairly simple: PG&E multiplies residential and
small commercial customers' rates as of June 10, 1996, by the
forecast gigawatt-hour sales for these two customer groups for each
of the years of the rate freeze period to determine the forecast of
overall revenues from these customer groups assuming no 10 percent
rate reduction. PG&E then multiplies the forecast revenues for each
of the years of the rate freeze period by 10 percent in order to
determine the forecast of target revenue reductions for each of the
years with the 10 percent rate reduction. PG&E uses the simple sum of
these annual target revenue reductions as the target revenue
reduction in its sizing model.
Once the target revenue reduction is known, PG&E uses the
following set of equations/2/ to solve iteratively for the RRB size
that is sufficient to support the 10 percent rate reduction and cover
the FTA charges.
b. Gross Avoided Revenue Requirements
----------------------------------
By definition, the amount of RRBs issued equals the amount of
Financed Transition Costs:
- ------------------
/2/ For purposes of this overview, the equations are presented in simplified
form, ignoring certain detailed assumptions (e.g., issuance costs and
ongoing costs and fees associated with the RRBs) that are outlined in
Appendix A. Chapter 5 describes the ratemaking methods which address how an
earlier end to the rate freeze period will affect the RRB transaction.
4-2
<PAGE>
Amount of RRBs issued = Amount of Financed Transition Costs
By financing transition costs, the Company avoids having to collect
from customers the revenue requirements necessary to recover those
transition costs (depreciation, return, and associated taxes) over the
rate freeze period. This gross avoided revenue requirement (the decrease
in revenue requirements excluding the revenue requirements necessary to
pay debt service on the RRBs) is a function of the amount of Financed
Transition Costs (the greater the amount of Financed Transition Costs,
the more revenue requirement avoided):
Gross avoided revenue = f {the amount of Financed Transition
requirement for rate Costs}
freeze period
c. RRB Debt Service Revenue Requirements
-------------------------------------
At the same time, however, by financing transition costs with the
RRBs, the Company incurs a new debt service revenue requirement that it
must collect from customers to cover the principal and interest and
related costs on the RRBs (the greater the amount of Financed Transition
Costs, the more RRB debt service revenue requirement incurred):
RRB debt service revenue = g {the amount of RRBs issued}
requirement for rate
freeze period
d. Net Change in Revenue Requirements
----------------------------------
The net reduction in the revenue requirements calculated by the
model is the simple difference between the gross revenue requirements
avoided by not
4-3
<PAGE>
having to collect the transition cost revenue requirements, less the
revenue requirements incurred by having to collect the debt service
revenue requirements on the RRBs. Thus, for a given RRB sizing:
Calculated net revenue = Gross avoided less RRB debt
requirements reduction revenue service revenue
for rate freeze period requirements for requirements
rate freeze period for rate freeze
period
In order to properly size the RRB issuance to deliver the 10 percent
rate reduction, this calculated net revenue requirement reduction should
equal the known target revenue reduction (determined as described above
in section B.1.a. Target Revenue Reductions) associated with the 10
percent rate reduction:
Calculated net revenue = Target revenue reduction for rate
requirement reduction for freeze period
rate freeze period
In summary, PG&E uses (1) the function for the gross avoided revenue
requirement for the rate freeze period, (2) the function for the rate
freeze period RRB debt service revenue requirement, and (3) the known
target revenue reduction for the rate freeze period, to arrive at the
amount of RRBs issued (i.e., the amount of Financed Transition Costs).
This amount is derived by an iterative process performed by PG&E's sizing
model. The size of the RRB issue must be solved for through an iterative
process because both the gross avoided revenue requirement and the RRB
debt service revenue requirement are essentially functions of the amount
of Financed Transition Costs. The result is that the amount of transition
costs financed with the RRBs provides gross
4-4
<PAGE>
avoided revenue requirements during the rate freeze period that are
sufficient to offset both the target net revenue reduction (based on the
10 percent rate reduction) and the debt service on the RRBs (see Figure
4-1).
Table 4-A presents the spreadsheet model PG&E uses to determine the
size of the RRBs. Based on assumptions currently in the model, the end
result is an estimated size for PG&E's RRB issuance of $3.094 billion,
which is the amount of the Financed Transition Costs plus RRB issuance
expenses. The gross avoided revenue requirements during the rate freeze
period are estimated to be $3.885 billion. As mentioned above, Appendix A
to this testimony contains a line-by-line explanation of the spreadsheet
sizing model.
2. Customer Benefits
-----------------
The customer benefits from achieving the target net revenue reduction
for the rate freeze period (based on the 10 percent rate reduction), coupled
with the RRB debt service revenue requirement, are presented as the present
value of the net revenue requirement differences relative to having no 10
percent rate reduction and no RRBs. Using a discount rate of 10 percent, the
present value of the customer benefits for PG&E is $469 million. Appendix A
also contains a summary of the customer benefits calculation contained in
the spreadsheet sizing model.
Both the size of the RRB issuance and the present value of the customer
benefits are estimates only. The size and benefits depend upon the RRBs'
principal amortization schedule, interest rate, term, and other factors,
which will be determined at the time the RRBs are issued.
4-5
<PAGE>
Figure 4-1
The omitted graphic reflects that with revenues at frozen rates, revenues
for Distribution, Transmission, Public Purpose Programs and PX(Supply) will
remain the same with or without frozen rate levels, and the component of
Residual CTC Revenues at frozen rate levels will equal the sum of Residual CTC
Revenues, FTA Charge Revenues and the 10% discount with a 10% rate reduction and
rate reduction bonds.
4-6
<PAGE>
<TABLE>
<CAPTION>
PACIFIC GAS & ELECTRIC COMPANY Page 1
TABLE 4-A
RATE REDUCTION BONDS -- SIZING CALCULATIONS
INPUT PAGE
($ in millions)
<S> <C> <C> <C> <C> <C>
Target revenue reduction, 1/1/1998 - 3/31/2002: 1998 1999 2000 2001 2002
- ----------------------------------------------- ---- ---- ---- ---- ----
Annual revenue reduction with 10% rate reduction $412 $416 $422 $427 $104
Total revenue reduction $1,781
<CAPTION>
3/31/98 6/30/98 9/30/98 12/31/98 3/31/99
--------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Quarterly revenue reduction with 10% rate reduction $103 $103 $103 $103 $104
Total revenue reduction $1,781
Transition cost amortization without debt financing:
- ----------------------------------------------------
Amortization period 4 years 1 quarter(s)
Number of amortization periods 17 quarters
Annual authorized pretax transition cost return 9.65%
Franchise fees & uncollectibles 2.0%
Transition cost amortization with debt financing:
- -------------------------------------------------
Amortization period 10 years 0 quarters
Number of amortization periods 40 quarters
Annual Quarterly
------ ---------
Interest (pre-tax carrying cost) 7.50% 1.88% (percentage of outstanding
principal balance)
Refundable costs/fees 1.50% 0.38% (percentage of original
principal)
Non-refundable costs/fees $0.11 $0.03 (fixed dollar amount)
Annual authorized pre-tax rate of return 13.56%
Rate reduction bond type 2 (Constant-principal)
(Enter 1 for mortgage-style, 2 for constant-principal)
Bond issuance expenses $25.0
<CAPTION>
Transition cost amounts financed: Net assets Financed Taxes
- --------------------------------- ---------- --------------
<S> <C> <C>
Generic Asset $1,819 $1,251
--------- --------
Total Net Assets plus Financed Taxes $3,069
Target revenue reduction, 1/1/1998 - 3/31/2002:
- -----------------------------------------------
Annual revenue reduction with 10% rate reduction
Total revenue reduction
<CAPTION>
6/30/99 9/30/99 12/31/99 3/31/00 6/30/00 9/30/00
-----------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Quarterly revenue reduction with 10% rate reduction $104 $104 $104 $105 $105 $105
Total revenue reduction
Transition cost amortization without debt financing:
- ----------------------------------------------------
Amortization period
Number of amortization periods
Annual authorized pretax transition cost return
Franchise fees & uncollectibles
Transition cost amortization with debt financing:
- -------------------------------------------------
Amortization period
Number of amortization periods
Interest (pre-tax carrying cost)
Refundable costs/fees
Non-refundable costs/fees
Annual authorized pre-tax rate of return
Rate reduction bond type
(Enter 1 for mortgage-style, 2 for constant-principal)
Bond issuance expenses
Transition cost amounts financed:
Generic Asset
Total Net Assets plus Financed Taxes
<CAPTION>
Target revenue reduction, 1/1/1998 - 3/31/2002:
- -----------------------------------------------
Annual revenue reduction with 10% rate reduction
Total revenue reduction
12/31/00 3/31/01 6/30/01 9/30/01 12/31/01 3/31/02
---------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Quarterly revenue reduction with 10% rate reduction $105 $107 $107 $107 $107 $104
Total revenue reduction
Transition cost amortization without debt financing:
- ----------------------------------------------------
Amortization period
Number of amortization periods
Annual authorized pretax transition cost return
Franchise fees & uncollectibles
Transition cost amortization with debt financing:
- -------------------------------------------------
Amortization period
Number of amortization periods
Interest (pre-tax carrying cost)
Refundable costs/fees
Non-refundable costs/fees
Annual authorized pre-tax rate of return
Rate reduction bond type
(Enter 1 for mortgage-style, 2 for constant-principal)
Bond issuance expenses
Transition cost amounts financed:
- ---------------------------------
Generic Asset
Total Net Assets plus Financed Taxes
</TABLE>
THIS INFORMATION IS BEING PROVIDED PURSUANT TO CPUC CODE SECTION 583.
<PAGE>
PACIFIC GAS & ELECTRIC COMPANY
TABLE 4-A
RATE REDUCTION BONDS -- SIZING CALCULATIONS
17-QUARTER AMORTIZATION CASE
($ in millions)
Assumptions: 17-quarter amortization
------------ 9.65 % pre-tax carrying cost
<TABLE>
<CAPTION>
1 12/31/97 3/31/98 6/30/98 9/30/98 12/31/98
-------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
2 Rate-Base Balances
------------------
3
4 EOY Transition Cost-Rate Base Balance 1,819 - - - 1,391
5 Annual Transition Cost-Rate Base Depreciation - - - 428
6 Average Transition Cost-Rate Base Balance - - - 1,605
7 Annual Pre-tax Return on Average Balance - - - 155
8
9
10 Financed Taxes:
---------------
11
12 EOY Financed Taxes Balance 1,251 - - - 956
13 Annual Financed Taxes Amortization - - - 294
14
15
16 Quarterly Revenue Requirement, 17-quarter
-----------------------------------------
Amortization
------------
17
18 Transition Cost-Rate Base Depreciation
(ln 5 divided by 4) 107 107 107 107
19 Pre-tax Return on Transition Cost-Rate Base
(ln 7 divided by 4) 39 39 39 39
20 Financed Tax (ln 13 divided by 4) 74 74 74 74
--------------------------------------------------
21 Subtotal (ln 18 + ln 19 + ln 20) 219 219 219 219
22 Franchise Fees & Uncollectibles 4 4 4 4
--------------------------------------------------
23 Total Revenue Requirement, 1/1/1998 - 3/31/2002 224 224 224 224
==================================================
<CAPTION>
1 3/31/99 6/30/99 9/30/99 12/31/99 3/31/00
------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
2 Rate-Base Balances
------------------
3
4 EOY Transition Cost-Rate Base Balance - - - 963 -
5 Annual Transition Cost-Rate Base Depreciation - - - 428 -
6 Average Transition Cost-Rate Base Balance - - - 1,177 -
7 Annual Pre-tax Return on Average Balance - - - 114 -
8
9
10 Financed Taxes:
---------------
11
12 EOY Financed Taxes Balance - - - 662 -
13 Annual Financed Taxes Amortization - - - 294 -
14
15
16 Quarterly Revenue Requirement, 17-quarter Amortization
------------------------------------------------------
17
18 Transition Cost-Rate Base Depreciation
(ln 5 divided by 4) 107 107 107 107 107
19 Pre-tax Return on Transition Cost-Rate Base
(ln 7 divided by 4) 28 28 28 28 18
20 Financed Tax (ln 13 divided by 4) 74 74 74 74 74
------------------------------------------------------------
21 Subtotal (ln 18 + ln 19 + ln 20) 209 209 209 209 199
22 Franchise Fees & Uncollectibles 4 4 4 4 4
------------------------------------------------------------
23 Total Revenue Requirement, 1/1/1998 - 3/31/2002 213 213 213 213 203
============================================================
<CAPTION>
1 6/30/00 9/30/00 12/31/00 3/31/01
------------------------------------------------
<S> <C> <C> <C> <C>
2 Rate-Base Balances
------------------
3
4 EOY Transition Cost-Rate Base Balance - - 535 -
5 Annual Transition Cost-Rate Base Depreciation - - 428 -
6 Average Transition Cost-Rate Base Balance - - 749 -
7 Annual Pre-tax Return on Average Balance - - 72 -
8
9
10 Financed Taxes:
---------------
11
12 EOY Financed Taxes Balance - - 368 -
13 Annual Financed Taxes Amortization - - 294 -
14
15
16 Quarterly Revenue Requirement, 17-quarter Amortization
------------------------------------------------------
17
18 Transition Cost-Rate Base Depreciation (ln 5 divided by 4) 107 107 107 107
19 Pre-tax Return on Transition Cost-Rate Base
(ln 7 divided by 4) 18 18 18 8
20 Financed Tax (ln 13 divided by 4) 74 74 74 74
------------------------------------------------
21 Subtotal (ln 18 + ln 19 + ln 20) 199 199 199 188
22 Franchise Fees & Uncollectibles 4 4 4 4
------------------------------------------------
23 Total Revenue Requirement, 1/1/1998 - 3/31/2002 203 203 203 192
================================================
<CAPTION>
1 6/30/01 9/30/01 12/31/01 3/31/02
------------------------------------------------
<S> <C> <C> <C> <C>
2 Rate-Base Balances
------------------
3
4 EOY Transition Cost-Rate Base Balance - - 107 0
5 Annual Transition Cost-Rate Base Depreciation - - 428 107
6 Average Transition Cost-Rate Base Balance - - 321 53
7 Annual Pre-tax Return on Average Balance - - 31 5
8
9
10 Financed Taxes:
---------------
11
12 EOY Financed Taxes Balance - - 74 0
13 Annual Financed Taxes Amortization - - 294 74
14
15
16 Quarterly Revenue Requirement, 17-quarter Amortization
------------------------------------------------------
17
18 Transition Cost-Rate Base Depreciation (ln 5 divided by 4) 107 107 107 107
19 Pre-tax Return on Transition Cost-Rate Base
(ln 7 divided by 4) 8 8 8 5
20 Financed Tax (ln 13 divided by 4) 74 74 74 74
------------------------------------------------
21 Subtotal (ln 18 + ln 19 + ln 20) 188 188 188 186
22 Franchise Fees & Uncollectibles 4 4 4 4
------------------------------------------------
23 Total Revenue Requirement, 1/1/1998 - 3/31/2002 192 192 192 189
================================================
</TABLE>
THIS INFORMATION IS BEING PROVIDED PURSUANT TO CPUC CODE SECTION 583.
<PAGE>
Pacific Gas & Electric Company
Table 4-A
RATE REDUCTION BONDS -- SIZING CALCULATIONS
BOND-ISSUANCE CASE
($ in millions)
Assumptions: 10-year amortization
----------- 7.5 % pre-tax carrying cost
<TABLE>
<CAPTION>
1 12/31/97 3/31/98 6/30/98 9/30/98 12/31/98 3/31/99 6/30/99 9/30/99
-------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
2 Debt Service
------------
3
4 Principal Payment [sigma of payments = $ 3,094 MM] 77 77 77 77 77 77 77
5 Interest Payment 58 57 55 54 52 51 49
6 Refundable Ongoing Costs/Fees 12 12 12 12 12 12 12
7 Non-refundable Ongoing Costs/Fees 0 0 0 0 0 0 0
--------------------------------------------------------
8 Quarterly Total Debt Service & Fees 147 146 144 143 141 140 138
=========================================================
9
10 Refundable Ongoing Costs/Fees Credit
------------------------------------
11
12 Quarterly Total Refundable Ongoing Costs/Fees
Credit (12) (12) (12) (12) (12) (12) (12)
13
14 Financed Taxes Carrying Cost Credit
-----------------------------------
15
16 EOQ Balance of Financed Taxes 1,251 1,219 1,188 1,157 1,126 1,094 1,063 1,032
17 Financed Taxes Amortization (reduce per ln 1) 31 31 31 31 31 31 31
18 Average Balance of Financed Taxes - - - 1,188 - - -
19 Carrying Cost on Balance of Financed Taxes - - - 9.65% - - -
20 Annual Financed Taxes Carrying Cost Credit - - - (115) - - -
21 Quarterly Financed Taxes Carrying Cost Credit (29) (29) (29) (29) (26) (26) (26)
22
23 Quarterly Revenue Requirement on Rate
-------------------------------------
Reduction Bonds
---------------
24
25 Principal Payment (ln 4) 77 77 77 77 77 77 77
26 Interest Payment (ln 5) 58 57 55 54 51 51 49
27 Total Ongoing Costs/Fees (ln 6 + ln 7) 12 12 12 12 12 12 12
28 Refundable Ongoing Costs/Fees Credit (ln 12) (12) (12) (12) (12) (12) (12) (12)
29 Financed Taxes Carrying Cost Credit (ln 21) (29) (29) (29) (29) (26) (26) (26)
--------------------------------------------------------
30 Subtotal (ln 25 + ln 26 + ln 27 + ln 28 + ln 29) 107 105 104 102 104 103 101
31 Franchise Fees & Uncollectibles 2 2 2 2 2 2 2
--------------------------------------------------------
32 Total Revenue Requirement, 12/31/98 - 12/31/07 109 107 106 104 106 105 103
========================================================
<CAPTION>
1 12/31/99 3/31/00 6/30/00 9/30/00 12/31/00 3/31/01 6/30/01
-------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
2 Debt Service
------------
3
4 Principal Payment [sigma of payments = $ 3,094 MM] 77 77 77 77 77 77 77
5 Interest Payment 48 46 45 44 42 41 39
6 Refundable Ongoing Costs/Fees 12 12 12 12 12 12 12
7 Non-refundable Ongoing Costs/Fees 0 0 0 0 0 0 0
--------------------------------------------------------
8 Quarterly Total Debt Service & Fees 137 135 134 132 131 130 128
=========================================================
9
10 Refundable Ongoing Costs/Fees Credit
------------------------------------
11
12 Quarterly Total Refundable Ongoing Costs/Fees Credit (12) (12) (12) (12) (12) (12) (12)
13
14 Financed Taxes Carrying Cost Credit
-----------------------------------
15
16 EOQ Balance of Financed Taxes 1,000 969 938 907 875 844 813
17 Financed Taxes Amortization (reduce per ln 1) 31 31 31 31 31 31 31
18 Average Balance of Financed Taxes 1,063 - - - 938 - -
19 Carrying Cost on Balance of Financed Taxes 9.65% - - - 9.65% - -
20 Annual Financed Taxes Carrying Cost Credit (103) - - - (91) - -
21 Quarterly Financed Taxes Carrying Cost Credit (26) (23) (23) (23) (23) (20) (20)
22
23 Quarterly Revenue Requirement on Rate Reduction Bonds
-----------------------------------------------------
24
25 Principal Payment (ln 4) 77 77 77 77 77 77 77
26 Interest Payment (ln 5) 48 46 45 44 42 41 39
27 Total Ongoing Costs/Fees (ln 6 + ln 7) 12 12 12 12 12 12 12
28 Refundable Ongoing Costs/Fees Credit (ln 12) (12) (12) (12) (12) (12) (12) (12)
29 Financed Taxes Carrying Cost Credit (ln 21) (26) (23) (23) (23) (23) (20) (20)
--------------------------------------------------------
30 Subtotal (ln 25 + ln 26 + ln 27 + ln 28 + ln 29) 100 101 100 98 97 98 97
31 Franchise Fees & Uncollectibles 2 2 2 2 2 2 2
--------------------------------------------------------
32 Total Revenue Requirement, 12/31/98 - 12/31/07 102 103 102 100 99 100 99
========================================================
<CAPTION>
1 9/30/01 12/31/01 3/31/02 6/30/02 9/30/02 12/31/02 3/31/03
-------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
2 Debt Service
------------
3
4 Principal Payment [sigma of payments = $ 3,094 MM] 77 77 77 77 77 77 77
5 Interest Payment 38 36 35 33 32 30 29
6 Refundable Ongoing Costs/Fees 12 12 12 12 12 12 12
7 Non-refundable Ongoing Costs/Fees 0 0 0 0 0 0 0
--------------------------------------------------------
8 Quarterly Total Debt Service & Fees 127 125 124 122 121 119 118
=========================================================
9
10 Refundable Ongoing Costs/Fees Credit
------------------------------------
11
12 Quarterly Total Refundable Ongoing Costs/Fees Credit (12) (12) (12) (12) (12) (12) (12)
13
14 Financed Taxes Carrying Cost Credit
-----------------------------------
15
16 EOQ Balance of Financed Taxes 782 750 719 688 657 625 594
17 Financed Taxes Amortization (reduce per ln 1) 31 31 31 31 31 31 31
18 Average Balance of Financed Taxes - 813 735 - - 672 -
19 Carrying Cost on Balance of Financed Taxes - 9.65% 9.65% - - 13.56% -
20 Annual Financed Taxes Carrying Cost Credit - (78) (18) - - (68) -
21 Quarterly Financed Taxes Carrying Cost Credit (20) (20) (18) (23) (23) (23) (19)
22
23 Quarterly Revenue Requirement on Rate Reduction Bonds
-----------------------------------------------------
24
25 Principal Payment (ln 4) 77 77 77 77 77 77 77
26 Interest Payment (ln 5) 38 36 35 33 32 30 29
27 Total Ongoing Costs/Fees (ln 6 + ln 7) 12 12 12 12 12 12 12
28 Refundable Ongoing Costs/Fees Credit (ln 12) (12) (12) (12) (12) (12) (12) (12)
29 Financed Taxes Carrying Cost Credit (ln 21) (20) (20) (18) (23) (23) (23) (19)
--------------------------------------------------------
30 Subtotal (ln 25 + ln 26 + ln 27 + ln 28 + ln 29) 95 94 94 88 87 85 87
31 Franchise Fees & Uncollectibles 2 2 2 2 2 2 2
--------------------------------------------------------
32 Total Revenue Requirement, 12/31/98 - 12/31/07 97 96 96 90 88 87 89
========================================================
<CAPTION>
1 6/30/03 9/30/03 12/31/03 3/31/04 6/30/04 9/30/04 12/31/04
-------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
2 Debt Service
------------
3
4 Principal Payment [sigma of payments = $ 3,094 MM] 77 77 77 77 77 77 77
5 Interest Payment 28 26 25 23 22 20 19
6 Refundable Ongoing Costs/Fees 12 12 12 12 12 12 12
7 Non-refundable Ongoing Costs/Fees 0 0 0 0 0 0 0
--------------------------------------------------------
8 Quarterly Total Debt Service & Fees 117 115 114 112 111 109 108
=========================================================
9
10 Refundable Ongoing Costs/Fees Credit
------------------------------------
11
12 Quarterly Total Refundable Ongoing Costs/Fees Credit (12) (12) (12) (12) (12) (12) (12)
13
14 Financed Taxes Carrying Cost Credit
-----------------------------------
15
16 EOQ Balance of Financed Taxes 563 532 500 469 438 407 375
17 Financed Taxes Amortization (reduce per ln 1) 31 31 31 31 31 31 31
18 Average Balance of Financed Taxes - - 563 - - - 438
19 Carrying Cost on Balance of Financed Taxes - - 13.56% - - - 13.56%
20 Annual Financed Taxes Carrying Cost Credit - - (76) - - - (59)
21 Quarterly Financed Taxes Carrying Cost Credit (19) (19) (19) (15) (15) (15) (15)
22
23 Quarterly Revenue Requirement on Rate Reduction Bonds
-----------------------------------------------------
24
25 Principal Payment (ln 4) 77 77 77 77 77 77 77
26 Interest Payment (ln 5) 28 26 25 23 22 20 19
27 Total Ongoing Costs/Fees (ln 6 + ln 7) 12 12 12 12 12 12 12
28 Refundable Ongoing Costs/Fees Credit (ln 12) (12) (12) (12) (12) (12) (12) (12)
29 Financed Taxes Carrying Cost Credit (ln 21) (19) (19) (19) (15) (15) (15) (15)
--------------------------------------------------------
30 Subtotal (ln 25 + ln 26 + ln 27 + ln 28 + ln 29) 86 84 83 86 84 83 81
31 Franchise Fees & Uncollectibles 2 2 2 2 2 2 2
--------------------------------------------------------
32 Total Revenue Requirement, 12/31/98 - 12/31/07 88 86 85 87 86 85 83
========================================================
<CAPTION>
1 3/31/05 6/30/05 9/30/05 12/31/05 3/31/06 6/30/06 9/30/06
-------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
2 Debt Service
------------
3
4 Principal Payment [sigma of payments = $ 3,094 MM] 77 77 77 77 77 77 77
5 Interest Payment 17 16 15 13 12 10 9
6 Refundable Ongoing Costs/Fees 12 12 12 12 12 12 12
7 Non-refundable Ongoing Costs/Fees 0 0 0 0 0 0 0
--------------------------------------------------------
8 Quarterly Total Debt Service & Fees 106 105 103 102 101 99 98
=========================================================
9
10 Refundable Ongoing Costs/Fees Credit
------------------------------------
11
12 Quarterly Total Refundable Ongoing Costs/Fees Credit (12) (12) (12) (12) (12) (12) (12)
13
14 Financed Taxes Carrying Cost Credit
-----------------------------------
15
16 EOQ Balance of Financed Taxes 344 313 281 250 219 188 156
17 Financed Taxes Amortization (reduce per ln 1) 31 31 31 31 31 31 31
18 Average Balance of Financed Taxes - - - 313 - - -
19 Carrying Cost on Balance of Financed Taxes - - - 13.56% - - -
20 Annual Financed Taxes Carrying Cost Credit - - - (42) - - -
21 Quarterly Financed Taxes Carrying Cost Credit (11) (11) (11) (11) (6) (6) (6)
22
23 Quarterly Revenue Requirement on Rate Reduction Bonds
-----------------------------------------------------
24
25 Principal Payment (ln 4) 77 77 77 77 77 77 77
26 Interest Payment (ln 5) 17 16 15 13 12 10 9
27 Total Ongoing Costs/Fees (ln 6 + ln 7) 12 12 12 12 12 12 12
28 Refundable Ongoing Costs/Fees Credit (ln 12) (12) (12) (12) (12) (12) (12) (12)
29 Financed Taxes Carrying Cost Credit (ln 21) (11) (11) (11) (11) (6) (6) (6)
--------------------------------------------------------
30 Subtotal (ln 25 + ln 26 + ln 27 + ln 28 + ln 29) 84 83 81 80 83 81 80
31 Franchise Fees & Uncollectibles 2 2 2 2 2 2 2
--------------------------------------------------------
32 Total Revenue Requirement, 12/31/98 - 12/31/07 86 84 83 81 84 83 81
========================================================
<CAPTION>
1 12/31/06 3/31/07 6/30/07 9/30/07 12/31/07
--------------------------------------------------------
<S> <C> <C> <C> <C> <C>
2 Debt Service
------------
3
4 Principal Payment [sigma of payments = $ 3,094 MM] 77 77 77 77 77
5 Interest Payment 7 6 4 3 1
6 Refundable Ongoing Costs/Fees 12 12 12 12 12
7 Non-refundable Ongoing Costs/Fees 0 0 0 0 0
------------------------------------------
8 Quarterly Total Debt Service & Fees 96 95 93 92 90
==========================================
9
10 Refundable Ongoing Costs/Fees Credit
------------------------------------
11
12 Quarterly Total Refundable Ongoing Costs/Fees Credit (12) (12) (12) (12) (12)
13
14 Financed Taxes Carrying Cost Credit
-----------------------------------
15
16 EOQ Balance of Financed Taxes 125 94 63 31 0
17 Financed Taxes Amortization (reduce per ln 1) 31 31 31 31 31
18 Average Balance of Financed Taxes 188 - - - 63
19 Carrying Cost on Balance of Financed Taxes 13.56% - - - 13.56%
20 Annual Financed Taxes Carrying Cost Credit (25) - - - (8)
21 Quarterly Financed Taxes Carrying Cost Credit (6) (2) (2) (2) (2)
22
23 Quarterly Revenue Requirement on Rate Reduction Bonds
-----------------------------------------------------
24
25 Principal Payment (ln 4) 77 77 77 77 77
26 Interest Payment (ln 5) 7 6 4 3 1
27 Total Ongoing Costs/Fees (ln 6 + ln 7) 12 12 12 12 12
28 Refundable Ongoing Costs/Fees Credit (ln 12) (12) (12) (12) (12) (12)
29 Financed Taxes Carrying Cost Credit (ln 21) (6) (2) (2) (2) (2)
------------------------------------------
30 Subtotal (ln 25 + ln 26 + ln 27 + ln 28 + ln 29) 78 81 80 78 77
31 Franchise Fees & Uncollectibles 2 2 2 2 2
------------------------------------------
32 Total Revenue Requirement, 12/31/98 - 12/31/07 80 83 81 80 78
==========================================
</TABLE>
<PAGE>
PACIFIC GAS & ELECTRIC COMPANY
TABLE 4-A
RATE REDUCTION BONDS -- SIZING CALCULATIONS
REVENUE REQUIREMENT DIFFERENCES
($ millions)
<TABLE>
<CAPTION>
1 12/31/97 3/31/98 6/30/98 9/30/98 12/31/98 3/31/99
----------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
2 Revenue Requirement Difference
------------------------------
3
4 Revenue Requirement, 17-quarter Transition Cost Amortization 224 224 224 224 213
5 Revenue Requirement, RRBs (109) (107) (106) (104) (106)
--------------------------------------------------
6 Subtotal Calculated Difference 115 116 118 119 107
7 Timing Adjustment (12) (13) (15) (16) (3)
--------------------------------------------------
8 Difference 103 103 103 103 104
==================================================
9
10 Sizing Calculation:
------------------
11
12 Total Calculated Difference, 1/1/1998 - 3/31/2002 (ln 6) $1,781 (Model iterates on amount financed on page 1, line
13 42, until this figure equals total target revenue
14 Proceeds on Bonds Issued $3,069 on page 1, line 8.)
------------------------
15 Bond Issuance Expense $25
------
16 Face Value of Bonds Issued $3,094
17
18 Customer Benefits Calculation:
-----------------------------
19
20 NPV of Quarterly Difference, 1/1/98 - 12/31/2007 (ln 8) $469
21 Annual Discount Rate 10.0%
22 Quarterly Discount Rate 2.5%
<CAPTION>
1 6/30/99 9/30/99 12/31/99 3/31/00 6/30/00 9/30/00
----------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
2 Revenue Requirement Difference
------------------------------
3
4 Revenue Requirement, 17-quarter Transition Cost Amortization 213 213 213 203 203 203
5 Revenue Requirement, RRBs (105) (103) (102) (103) (102) (100)
----------------------------------------------------
6 Subtotal Calculated Difference 109 110 112 99 101 102
7 Timing Adjustment (4) (6) (7) 6 5 3
----------------------------------------------------
8 Difference 104 104 104 105 105 105
====================================================
9
10 Sizing Calculation:
------------------
11
12 Total Calculated Difference, 1/1/1998 - 3/31/2002 (ln 6)
13
14 Proceeds on Bonds Issued
------------------------
15 Bond Issuance Expense
16 Face Value of Bonds Issued
17
18 Customer Benefits Calculation:
-----------------------------
19
20 NPV of Quarterly Difference, 1/1/98 - 12/31/2007 (ln 8)
21 Annual Discount Rate 10.0%
22 Quarterly Discount Rate 2.5%
<CAPTION>
1 12/31/00 3/31/01 6/30/01 9/30/01 12/31/01 3/31/02
-----------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
2 Revenue Requirement Difference
------------------------------
3
4 Revenue Requirement, 17-quarter Transition Cost Amortization 203 192 192 192 192 189
5 Revenue Requirement, RRBs (99) (100) (99) (97) (96) (96)
-----------------------------------------------------
6 Subtotal Calculated Difference 104 92 93 95 96 93
7 Timing Adjustment 2 15 13 12 10 11
-----------------------------------------------------
8 Difference 105 107 107 107 107 104
=====================================================
9
10 Sizing Calculation:
------------------
11
12 Total Calculated Difference, 1/1/1998 - 3/31/2002 (ln 6)
13
14 Proceeds on Bonds Issued
------------------------
15 Bond Issuance Expense
16 Face Value of Bonds Issued
17
18 Customer Benefits Calculation:
-----------------------------
19
20 NPV of Quarterly Difference, 1/1/98 - 12/31/2007 (ln 8)
21 Annual Discount Rate 10.0%
22 Quarterly Discount Rate 2.5%
<CAPTION>
1 6/30/02 9/30/02 12/31/02 3/31/03 6/30/03 9/30/03
----------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
2 Revenue Requirement Difference
------------------------------
3
4 Revenue Requirement, 17-quarter Transition Cost Amortization -- -- -- -- -- --
5 Revenue Requirement, RRBs (90) (88) (87) (89) (88) (86)
----------------------------------------------------
6 Subtotal Calculated Difference (90) (88) (87) (89) (88) (86)
7 Timing Adjustment -- -- -- -- -- --
----------------------------------------------------
8 Difference (90) (88) (87) (89) (88) (86)
====================================================
9
10 Sizing Calculation:
------------------
11
12 Total Calculated Difference, 1/1/1998 - 3/31/2002 (ln 6)
13
14 Proceeds on Bonds Issued
------------------------
15 Bond Issuance Expense
16 Face Value of Bonds Issued
17
18 Customer Benefits Calculation:
-----------------------------
19
20 NPV of Quarterly Difference, 1/1/98 - 12/31/2007 (ln 8)
21 Annual Discount Rate 10.0%
22 Quarterly Discount Rate 2.5%
<CAPTION>
1 12/31/03 3/31/04 6/30/04 9/30/04 12/31/04 3/31/05
----------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
2 Revenue Requirement Difference
------------------------------
3
4 Revenue Requirement, 17-quarter Transition Cost Amortization -- -- -- -- -- --
5 Revenue Requirement, RRBs (85) (87) (86) (85) (83) (86)
----------------------------------------------------
6 Subtotal Calculated Difference (85) (87) (86) (85) (83) (86)
7 Timing Adjustment -- -- -- -- -- --
----------------------------------------------------
8 Difference (85) (87) (86) (85) (83) (86)
====================================================
9
10 Sizing Calculation:
------------------
11
12 Total Calculated Difference, 1/1/1998 - 3/31/2002 (ln 6)
13
14 Proceeds on Bonds Issued
------------------------
15 Bond Issuance Expense
16 Face Value of Bonds Issued
17
18 Customer Benefits Calculation:
-----------------------------
19
20 NPV of Quarterly Difference, 1/1/98 - 12/31/2007 (ln 8)
21 Annual Discount Rate 10.0%
22 Quarterly Discount Rate 2.5%
<CAPTION>
1 6/30/05 9/30/05 12/31/05 3/31/06 6/30/06 9/30/06
----------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
2 Revenue Requirement Difference
------------------------------
3
4 Revenue Requirement, 17-quarter Transition Cost Amortization -- -- -- -- -- --
5 Revenue Requirement, RRBs (84) (83) (81) (84) (83) (81)
----------------------------------------------------
6 Subtotal Calculated Difference (84) (83) (81) (84) (83) (81)
7 Timing Adjustment -- -- -- -- -- --
----------------------------------------------------
8 Difference (84) (83) (81) (84) (83) (81)
====================================================
9
10 Sizing Calculation:
------------------
11
12 Total Calculated Difference, 1/1/1998 - 3/31/2002 (ln 6)
13
14 Proceeds on Bonds Issued
------------------------
15 Bond Issuance Expense
16 Face Value of Bonds Issued
17
18 Customer Benefits Calculation:
-----------------------------
19
20 NPV of Quarterly Difference, 1/1/98 - 12/31/2007 (ln 8)
21 Annual Discount Rate 10.0%
22 Quarterly Discount Rate 2.5%
<CAPTION>
1 12/31/06 3/31/07 6/30/07 9/30/07 12/31/07
---------------------------------------------
<S> <C> <C> <C> <C> <C>
2 Revenue Requirement Difference
------------------------------
3
4 Revenue Requirement, 17-quarter Transition Cost Amortization -- -- -- -- --
5 Revenue Requirement, RRBs (80) (83) (81) (80) (78)
---------------------------------------------
6 Subtotal Calculated Difference (80) (83) (81) (80) (78)
7 Timing Adjustment -- -- -- -- --
---------------------------------------------
8 Difference (80) (83) (81) (80) (78)
=============================================
9
10 Sizing Calculation:
------------------
11
12 Total Calculated Difference, 1/1/1998 - 3/31/2002 (ln 6)
13
14 Proceeds on Bonds Issued
------------------------
15 Bond Issuance Expense
16 Face Value of Bonds Issued
17
18 Customer Benefits Calculation:
-----------------------------
19
20 NPV of Quarterly Difference, 1/1/98 - 12/31/2007 (ln 8)
21 Annual Discount Rate 10.0%
22 Quarterly Discount Rate 2.5%
</TABLE>
THIS INFORMATION IS BEING PROVIDED PURSUANT TO CPUC CODE SECTION 583.
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
CHAPTER 5
REVENUE REQUIREMENTS AND RATEMAKING MECHANISMS
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
CHAPTER 5
REVENUE REQUIREMENTS AND RATEMAKING MECHANISMS
A. INTRODUCTION
------------
This chapter describes PG&E's proposed ratemaking for the RRBs. The
mechanics of the CTC Ratemaking Mechanism and the RRB Proceeds Memorandum
Account are proposed by PG&E to meet the following goals: (1) to prevent
cost shifting between residential/small commercial customers and all other
customers, and (2) to ensure that the rate reduction provided to
residential and small commercial customers during the rate freeze period is
commensurate with the amount of transition costs financed by the RRBs.
This chapter:
1. Describes how the RRBs and 10 percent rate reduction will be
incorporated into the CTC Ratemaking Mechanism. The purpose of the CTC
Ratemaking Mechanism, proposed by PG&E in its CTC Application (A.96
-08-070), is to recover the CTC revenue requirements associated with
PG&E's transition costs;
2. Presents PG&E's proposal for the RRB Memorandum Account, which ensures
that the size of the RRBs is commensurate with the amount of the 10
percent rate reduction given to residential and small commercial
customers during the rate freeze period; and
3. Describes how additional benefits and credits of the RRBs that are not
received by residential and small commercial customers during the rate
freeze period will be credited to these customers after the rate
freeze period.
This chapter is organized as follows:
B. CTC Ratemaking Mechanism
C. Financial Accounting
D. RRB Memorandum Account
5-1
<PAGE>
E. Headroom Considerations
Proforma tariff language for the CTC Ratemaking Mechanism and the RRB
Memorandum Account is contained in Appendix C.
B. CTC RATEMAKING MECHANISM
------------------------
PG&E's proposal ensures that all customers other than residential and
small commercial customers will pay the same amount of transition costs
that they would have, absent the RRB issuance and the 10 percent rate
reduction. Given the rate freeze, this means that the rate freeze period
would end at the same time as it would have absent the RRB issuance. This
section describes the CTC Ratemaking Mechanism, as proposed in PG&E's CTC
Filing (A.96-08-070)/1/, then explains how PG&E proposes to incorporate the
RRBs and the 10 percent rate reduction into the CTC Ratemaking Mechanism to
prevent cost shifting between residential and small commercial customers
and all other customers.
1. Overview
--------
As described in PG&E's CTC Application (A.96-08-070), PG&E
proposes to establish a CTC Ratemaking Mechanism which consists of one
CTC Revenue Account and three CTC Cost Accounts./2/ Each month during
the rate freeze period, the CTC Revenue Account is credited with
residual CTC revenues from billed revenues from all customers. As
proposed in PG&E's Cost Separation Application (A.96-12-009), billed
revenues under the rate freeze will first be used to recover all of
PG&E's non-CTC costs (e.g., distribution revenue requirements, Public
Purpose Programs, etc.). Any remaining revenue would be considered
residual CTC Revenues, available to recover the CTC revenue
requirements in each of the three
________________________________
/1/ In its CTC Filing (A.96-08-070), PG&E proposed that the proceeds from the
RRBs be credited to the CTC Revenue Account when received. The proposal for
treatment of these proceeds in this filing supersedes any previous
proposals.
/2/ The three CTC Cost Accounts are the Current Costs CTC Account, the
Accelerated Costs CTC Account, and the Post 2001-Eligible Costs CTC
Account.
5-2
<PAGE>
CTC Cost Accounts within the CTC Ratemaking Mechanism. As these
revenue requirements are recovered, depreciation expense is recovered.
To the extent that revenue is available, the recovery of depreciation
of these transition costs may be accelerated.
Due to the manner in which CTC revenues are available residually
under the rate freeze, the imposition of an FTA charge on residential
and small commercial customers would decrease the residual amount of
CTC revenues available to recover CTC revenue requirements. In
addition, the 10 percent rate reduction would directly reduce the CTC
revenues. (The rest of this chapter will refer to this combined
reduction in residual CTC revenues as "CTC revenue reduction.") All
else being equal, the result of this CTC revenue reduction would be
that certain CTC revenue requirements that could have been recovered
may not now be recovered, but would remain as debit balances in the
---
CTC Cost Accounts. PG&E proposes to remedy this as described below. On
a forecast basis, as described in Chapter 4, the transition costs
associated with this revenue requirement reduction are equivalent to
the Financed Transition Costs that are financed through RRBs.
2. Proposed Mechanics to Incorporate RRBs and 10 Percent Rate Reduction
--------------------------------------------------------------------
and to Prevent Cost Shifting
----------------------------
To incorporate the 10 percent rate reduction and RRBs into the
CTC Ratemaking Mechanism, PG&E proposes that each month during the
rate freeze period, in addition to the actual residual CTC revenues
received, the CTC Revenue Account be credited with an imputed revenue
amount equal to the CTC revenue reduction due to the FTA charge and 10
percent reduction for residential and small commercial customers. This
total additional credit amount is the amount of revenue that would
have been collected from residential and small commercial customers
and used to recover the CTC revenue requirements, absent the 10
percent rate reduction and the FTA charge. On a monthly basis, these
imputed revenues will be
5-3
<PAGE>
used to credit specific revenue requirements in the CTC Cost Accounts,
in the manner described in PG&E's CTC filing (A.96-08-070).
To the extent that revenues are collected under the FTA charge
before the CTC Revenue Account is established, PG&E will credit that
revenue plus interest to the CTC Revenue Account when it is
established. Similarly, to the extent revenues are reduced by the 10
percent rate reduction before the CTC Revenue Account is established,
PG&E will credit that revenue plus interest to the CTC Revenue Account
when it is established.
Based on these entries, the balances in the CTC Cost Accounts may
reach zero at some time during the rate freeze period. This determines
the point at which all CTC revenue requirements would have been
recovered, absent the 10 percent rate reduction and the FTA charge. At
this point, the rate freeze will end for all customers./3/
This approach ensures that the rate freeze ends at the same time
as it otherwise would have, absent the 10 percent rate reduction and
the FTA charge. Thus, large customers' responsibility for paying
transition costs is unaffected by the 10 percent discount and the RRB
issuance.
In addition, this approach ensures that residential and small
commercial customers pay the appropriate amount for transition costs,
subject to one very important condition: that the actual CTC revenue
reduction for residential and small commercial customers must be
commensurate with the amount of transition costs
______________________________
/3/ As described in PG&E's CTC filing, the end of the rate freeze is subject
to the firewall mechanism, which is designed to address the recovery of
CTC exemptions. The firewall mandated by AB 1890 (P.U. Code (S)330(v)(2))
ensures that the two categories of customers pay only for their own CTC
exemptions. The two categories of customers are residential/small
commercial customers and all other customers. CTC collection and the rate
freeze would only continue for a category of customers in order to pay for
its own exemptions. Once these are recovered the rate freeze for that
customer category would end.
5-4
<PAGE>
financed by the RRBs (Financed Transition Costs). The RRB Memorandum
Account, described in Section D below, ensures that this is the case.
C. FINANCIAL ACCOUNTING
--------------------
Consistent with the ratemaking established for the RRBs, PG&E plans to
defer for financial reporting purposes amortization of the portion of
transition costs that relates to the securitization of the Transition
Property. These deferred costs will be amortized to expense over the 10-
year period of the RRBs, and will result in a matching for financial
reporting purposes of the effects of the securitization transaction. The
deferral for financial reporting purposes will have no effect on the
ratepayers.
D. RRB MEMORANDUM ACCOUNT
----------------------
PG&E proposes to establish the RRB Memorandum Account. The purpose of
this account is (1) to determine whether it is necessary for PG&E to issue
additional RRBs and (2) to determine the amount of credits that should be
provided to residential and small commercial customers after the rate
freeze period.
1. RRB Proceeds Adjustment Memorandum Subaccount
---------------------------------------------
When the RRBs are sized, the transition costs associated with the
forecast reduction in CTC revenues received from residential and small
commercial customers due to the 10 percent rate reduction and FTA
charge will be exactly equal to the Financed Transition Costs. As
described in Chapter 4, the RRBs are sized by setting these two
amounts equal to each other. However, the actual residential and small
commercial customer CTC revenue reduction is likely to be more or less
than originally forecast, if actual sales to these customers are
higher or lower than was forecast when the RRBs were sized.
If sales are higher than originally forecast, the CTC revenue
reduction will also be higher than was expected when the bonds were
sized. In this case, the amount of transition costs financed, or the
Financed Transition Costs, in the original financing will not be
sufficient to cover actual revenue reduction provided to residential
and
5-5
<PAGE>
small commercial customers. If this is the case, PG&E requests
approval for additional RRBs to be issued to finance the necessary
additional amount of transition costs to make up for the additional
CTC revenue reduction.
If, for any reason, additional RRBs cannot be issued to make up
for the additional CTC revenue reduction, PG&E proposes that it
increase residential and small commercial customers' revenue
requirements in the post-rate freeze period, amortizing the additional
revenue requirement over the remaining life of the RRBs.
If, on the other hand, sales are lower than originally forecast,
the CTC revenue reduction will also be lower than was expected when
the bonds were sized. In this case, not all of the revenue reduction
associated with the RRBs will have been provided to residential and
small commercial customers during the rate freeze period. In this
case, the remainder of the savings to which they are entitled will be
passed on to these customers after the rate freeze period.
Similarly, if transition costs are recovered early, thereby
ending the rate freeze early, the CTC revenue reduction may be lower
than was expected when the bonds were sized. As in the case where
sales are lower than expected, not all of the revenue reduction
associated with the RRBs will have been provided to residential and
small commercial customers. The remainder of the savings to which they
are entitled will be passed on to them after the rate freeze period.
In order to determine whether to issue additional RRBs or whether
it is necessary to provide additional benefits to residential and
small commercial customers after the rate freeze period, PG&E proposes
to establish within the RRB Memorandum Account, the RRB Proceeds
Adjustment Memorandum Subaccount, which will track the difference
between the savings achieved by the RRBs and the 10 percent rate
reduction provided to residential and small commercial customers. The
balance in this subaccount may determine that it is necessary for PG&E
to issue additional RRB's. Based on actual sales to residential and
small commerical
5-6
<PAGE>
customer and the iterative sizing model described in Chapter 4, PG&E
will determine the necessary additional RRB issuance, and the
corresponding amount of Financed Transaction Costs. Conversely, the
balance in the RRB proceeds Adjustment Memorandum Subaccount may
determine that PG&E must provide additional benefits to residential and
small customers after the rate freeze period. If this is the case, the
credit balance will be given to ratepayers in the post-rate freeze
period, as described in Section D.2 below.
PG&E proposes additional subaccounts in the RRB Memorandum
Account to track other credits that may be given to residential and
small commercial customers in the post-rate freeze period. These
credits are described later in Section F of this chapter. The ending
balance in the RRB Memorandum Account will either be debited or
credited to residential and small commercial customers' revenue
requirements in the post-rate freeze period.
2. Post-Rate Freeze Period Credits to Residential and Small Commercial
-------------------------------------------------------------------
Customers
---------
This section describes the treatment of any credits due to
residential and small commercial customers during the post-rate freeze
period as a result of the RRB issuance. Adjustments will be necessary
due to: (1) the refund of servicing fees paid to PG&E after the rate
freeze period, (2) the carrying cost earned on the difference in
timing from when PG&E receives FTA charge revenue from ratepayers and
when PG&E actually remits the funds to the Bond Trustee, (3) the
investment earnings on the funds held by the Bond Trustee in the
collection account between distribution dates, and (4) any
overcollateralization of FTA charge collections that are in excess of
total debt service. In addition, credits due to ratepayers may be
necessary due to (5) sizing of the RRBs and (6) post-rate freeze
period savings from the RRBs. In each of these six cases, the credit
to ratepayers will be given to the residential and small commercial
customers after the rate freeze period. These credits will be tracked
in separate subaccounts within the RRB Memorandum
5-7
<PAGE>
Account, and interest will be applied, based on the three-month
commercial paper rate. These subaccounts are described below.
a. Servicing Fees Memorandum Subaccount
------------------------------------
Residential and small commercial customers will pay for
servicing fees as part of the FTA charge. As described in Chapter
3, most of these fees, if paid to PG&E, are refundable to
residential and small commercial customers. During the rate
freeze period, the refund is captured in the imputed revenues to
the CTC Revenue Account. Therefore, there is no need for a direct
refund. After the rate freeze period, this refund will be
credited to residential and small commercial customers. In the
event PG&E is replaced as servicer, these fees will be retained
by the new servicer and not returned to ratepayers.
b. Carrying Cost Memorandum Subaccount
-----------------------------------
As described in Chapter 3, PG&E will receive FTA revenues
daily, but will remit these funds to the Bond Trustee on a
monthly basis. The interest earned on this revenue should be
returned to residential and small commercial customers. The
interest earned will be based on the one-month commercial paper
rate and will be credited to the residential and small commercial
customers.
c. SPE Investment Earnings Memorandum Subaccount
---------------------------------------------
As described in Chapter 3, the Bond Trustee will receive
funds from PG&E on a monthly basis, but will pay the bond holders
on a quarterly basis. Any investment earnings from these funds
will be credited to residential and small commercial customers.
d. Overcollateralization Memorandum Subaccount
-------------------------------------------
PG&E must remit all revenues collected through the FTA
charge to the Bond Trustee. If the FTA revenues remitted to the
Bond Trustee exceed the amount necessary to pay the total debt
service and other costs associated with
5-8
<PAGE>
the RRBs, the extra amount will be credited to residential and
small commercial customers.
e. RRB Proceeds Adjustment Memorandum Subaccount
---------------------------------------------
As described in Section D.1 of this chapter, this RRB
Proceeds Adjustment Memorandum Subaccount will track whether
residential and small commercial customers have received rate
reduction benefits commensurate with the amount of transition
costs financed by RRBs. In the event that these customers' rate
reductions over the rate freeze period turn out to be too small,
residential and small commercial customers will receive an
appropriate credit, after the rate freeze period, over the
remaining RRB repayment period. As described earlier in Section
D.1, in the event the amount of Financed Transition Costs were
too small, additional RRBs may be issued.
f. Post-Rate Freeze Period Financed Tax Memorandum Subaccount
----------------------------------------------------------
Chapter 4 of this filing describes the net benefits to
residential and small commercial customers as a result of the RRB
issuance. These benefits are passed to customers through the
sizing calculation and reduction in revenues during the rate
freeze period. However, as described in Section B.2 of Appendix
A, there are benefits due to carrying cost savings associated
with the financed taxes that occur after the rate freeze period.
These savings will be credited to residential and small
commercial customers in the post-rate freeze period.
E. HEADROOM CONSIDERATIONS
-----------------------
As a result of the RRB Memorandum Account described in this chapter,
the RRB issuance is headroom neutral. This means that the issuance of the
RRBs does not have an effect on PG&E's risk of recovery of transition
costs. Thus, PG&E would recover the same amount of transition costs as it
would have had there been no RRB issuance. The following example
illustrates this point.
5-9
<PAGE>
For illustrative purposes only, assume that PG&E has $10 billion of
transition costs to recover during the rate freeze period. Assume also
that, based on forecasts of sales and the Power Exchange (PX) price, PG&E
expects to collect exactly that amount by the end of the rate freeze
period, with no excess headroom. If, however, the actual PX price exceeds
forecast, resulting in an additional $1 billion in net costs, PG&E would
fail to recover $1 billion of transition costs.
Now assume that PG&E finances $3.5 billion of its $10 billion of
transition costs, leaving $6.5 billion of transition costs to be collected
by the end of the rate freeze period, subject to available headroom. Since
the financing is linked to a 10 percent rate reduction for residential and
small commercial customers, available CTC revenue is reduced. In addition,
PG&E must pass on the revenue it receives from the FTA charge (net of any
servicing compensation or other ongoing expenses) to RRB investors. The net
reduction in available revenue over the rate freeze period due to these two
effects is exactly equal to $3.5 billion, which is the same as the amount
of the Financed Transition Costs (the RRB Memorandum Account ensures that
this is the case). Thus, even though there is only $6.5 billion of
transition costs to be collected, the available revenue has been reduced by
this amount as well.
Suppose, as above, that the PX price is higher than forecast,
resulting in $1 billion of additional net costs, so that there are a total
of $7.5 billion of transition costs to be collected by the end of the rate
freeze period. The net reduction in available revenue over the transition
period due to the 10 percent rate reduction and FTA charge is still $3.5
billion. Therefore, PG&E has $6.5 billion of available revenue to recover
the $7.5 billion in transition costs. As in the example without financing,
PG&E would fail to collect $1 billion of transition costs.
This example shows that the issuance of the RRBs and corresponding 10
percent rate reduction do not modify the risk of transition cost recovery.
5-10
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
CHAPTER 6
RATE PROPOSAL
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
CHAPTER 6
RATE PROPOSAL
A. INTRODUCTION
------------
The purpose of this chapter is to present PG&E's ratemaking proposal
for residential and small commercial customers. The remainder of this
chapter is organized as follows:
B. Discount Applicability
C. Calculation of Discount
D. Calculation of Fixed Transition Amount (FTA) Charge
E. Non-bypassability
F. FTA Charge True-up Mechanism
B. DISCOUNT APPLICABILITY
----------------------
Since AB 1890 does not impose a size limitation on the residential
class, PG&E proposes that all residential electric customers receive the 10
percent rate reduction.
AB 1890 defines a small commercial customer as "a customer that has a
maximum peak demand of less than 20 kW" (P.U. Code (S)331(h)). Unlike
Southern California Edison Company and San Diego Gas and Electric Company,
not all of PG&E's commercial customers with billing demands greater than 20
kW are demand metered. In the absence of demand metering for these
customers, PG&E proposes that the discount be applied to all customers on
small commercial electric rate Schedules A-1 and A-6.
In addition to the small commercial customers that are not demand
metered, all Schedule A-10 and E-19V customers with peak demand of less
than 20 kW will be included in the small commercial classification.
Applicability of the below-20 kW cutoff will be based on the customer's
maximum billing demand, which must be less than 20 kW for at least nine
billing periods during the most recent 12 month period. The applicability
of the discount for these customers shall be determined on a one-time basis
6-1
<PAGE>
on January 1, 1998. The determination of the applicability of the discount
for this class of customers will not be reassessed after January 1,
1998./1/
If a new residential customer or small commercial customer, as defined
above, receives service from PG&E after January 1, 1998, but before the end
of the rate freeze period, that customer will receive the 10 percent
discount. Correspondingly, these new customers would be obligated to pay
the FTA charge irrespective of when service begins. In addition, new PG&E
customers after the rate freeze period will be required to pay the FTA
charge.
Table 6-1 shows all electric schedules that will qualify for the 10
percent rate reduction.
C. CALCULATION OF DISCOUNT
-----------------------
The 10 percent discount will be applied on January 1, 1998, and
continue through the rate freeze period. PG&E proposes to reduce the bills
of customers taking service under the applicable schedules by 10 percent.
Customers will see their total bill calculated as usual (that is, using the
June 10, 1996 rates that were frozen by AB 1890 (P.U. Code (S)368(a))) and
a separate line item will be included on the customer's bill to show the
billed amount reduced by 10 percent./2/
In addition, to the extent feasible, a separate bill line item will
show the customer's monthly payment under the FTA charge. The FTA charge
line item will be in addition to the power exchange, transmission,
distribution, and public purpose program (PPP) charge information displayed
on customers' bills./3/ Total rates during the rate freeze
_____________________________
/1/ Consistent with AB 1890, the small commercial class excludes customer
classes not typically considered "commercial." Therefore, all
streetlighting, traffic control, agriculture, and pumping customers
are excluded from the class of customers entitled to receive the 10
percent discount on January 1, 1998.
/2/ Customers who elect direct access when it becomes available on January
1, 1998, will receive the 10 percent discount based on what their
full-service June 10, 1996 bill would have been.
/3/ The sum of these components is subtracted from total rates to
determine the Competition Transition Charge (CTC) and other non-
bypassable charges applicable to residential and small commercial
customers.
6-2
<PAGE>
period will not be affected by this additional charge because the residual
CTC amount will be reduced by the FTA charge as mandated by P.U. Code
(S)330 (v) in order to maintain the frozen rate levels.
D. CALCULATION OF FTA CHARGE
-------------------------
Residential and small commercial customers who receive the 10 percent
rate reduction are required to fund payments on the RRBs through the FTA
charge. The FTA charge is defined by AB 1890 as a non-bypassable, separate
charge that is authorized by the Commission in a Financing Order to recover
Financed Transition Costs and the costs of providing, recovering, financing
or refinancing transition costs, including the costs of issuing, servicing,
and retiring RRBs (P.U. Code (S)840(d)). The FTA charge will be comprised
of the following components: (1) scheduled debt service on the RRBs, (2)
servicing fees, (3) Bond Trustee fees, (4) overcollateralization, (5)
allowance for uncollectibles and (6) other ongoing expenses. Appendix D
describes in detail the cash flow model used to calculate the FTA charge
for residential and small commercial customers. PG&E's proposed tariff
language describing the FTA charge procedure applicable to residential and
small commercial customers is provided in Appendix E.
When the RRBs are issued PG&E proposes to file an Issuance Advice
Letter with the Commission seeking approval, no less than five business
days prior to the close of the sale of the RRBs, to ensure that FTA
revenues from the small commercial and residential customer classes are
sufficient to make the necessary monthly remittance of the FTA charge to
the Bond Trustee. The Issuance Advice Letter shall include a description of
the FTA charge calculation, the bond issuance amount, identities of one or
more Special Purpose Entities (SPE), identities of one or more Issuers, and
identification of the FTA charge as Transition Property. It is imperative
that the FTA charge be in place and approved prior to the issuance of RRBs
so that the RRBs receive the highest possible credit rating. Any delay in
implementing the initial tariff would be detrimental to the Issuer's
ability to complete the RRB issuance. Although RRBs are expected to be
6-3
<PAGE>
issued in the fourth quarter of 1997, the actual rate reduction will not
occur until January 1, 1998, as described in AB 1890 (P.U. Code (S)330(w)).
Additionally, PG&E may issue more than one series of RRBs. For
example, two series of RRBs may be issued over a two-month period. PG&E
proposes that the same procedure as described for the initial series be
used for additional series if necessary.
E. NON-BYPASSABILITY
-----------------
Consistent with P.U. Code (S)840(d), which requires that the FTA
charge be non-bypassable, and with P.U. Code (S)331(d), which defines the
line of demarcation between residential/small commercial customers and all
other customers, PG&E proposes the use of a non-bypassable charge
comparable to that for CTC. In the absence of a non-bypassable charge,
customers could bypass their responsibility to repay the RRB if:/4/
. another entity taking over a portion of PG&E's existing service
territory that includes residential and/or small commercial customers,
or
. a small commercial customer whose load grows such that the customer is
no longer in the eligible class.
For customers in the first non-bypass category, PG&E proposes that an
ongoing charge be assessed. RRB customers who leave PG&E's system through
annexation of the Company's service territory must pay an ongoing charge
based on pre-recorded usage or current usage until the elimination of the
FTA charge. This approach is similar to that proposed in PG&E's October 21,
1996 CTC filing (A.96-08-070) for departing load.
In its CTC filing, PG&E proposed a two-step procedure for transition
cost recovery from departing load customers. During the rate freeze period,
departing load customers would pay an ongoing charge based on either: (1)
the last 12 months of the customer's
________________________________
/4/ The definition of bypass does not include a customer who relocates outside
of PG&E's service territory to a new location. These customers cannot be
billed the FTA charge.
6-4
<PAGE>
recorded pre-departure use, (2) an average derived from the last three
years of recorded use, or (3) actual use. As proposed in the CTC filing, at
the end of the rate freeze period, each departing load customer would be
charged a final lump sum payment based on the net present value of PG&E's
projected post-2001 transition costs. PG&E is not proposing a final lump
sum payment option to departing customers responsible for the FTA charge.
It will still give these customers an option to pay their ongoing charge
based on one of the three above usage data.
Customers in the second category will have the opportunity to continue
to take service on the RRB-eligible schedule or take service off their new
applicable schedule and pay an ongoing charge based on historical data.
F. FIXED TRANSITION AMOUNT CHARGE TRUE-UP MECHANISM
------------------------------------------------
As provided for in P.U. Code (S)841(c), PG&E will file a True-Up
Mechanism Advice Letter at least annually to adjust the FTA charge. PG&E
proposes that these advice filings, which are intended to be ministerial in
nature, be approved within 15 days of filing. These filings are intended to
assure that the actual revenues collected under the FTA charge are neither
more nor less than those required to repay the RRBs as scheduled. The
revised FTA charges will be calculated as described in Appendix D, except
that: (1) the amount of the debt service and related expenses for the next
year shall be increased or decreased by the amount by which actual
remittances of FTA charges to the Bond Trustee collection account through
the end of the month preceding the month of calculation (the "Transaction
Period") was less than or exceeded the aggregate actual debt service and
related expenses for the Transaction Period;/5/ (2) forecasted sales for
the remaining years of the transaction will be revised based on the
methodology described in Appendix B;/6/ (3) estimated administrative fees
and
_______________________________
/5/ The discrepancy could arise from a number of causes, including, for
example, incorrect estimations, servicer defaults, or unexpected
losses.
/6/ It is not necessary to litigate a new sales forecast prior to updating
the FTA charge since annual updates to the FTA charge will provide an
opportunity to make necessary adjustments to the FTA charge.
6-5
<PAGE>
expenses will be modified to reflect changed circumstances; (4) assumed
losses will be modified to equal the percentage of losses actually
experienced during the most recent 12-month billing period for which such
information is available; and (5) an adjustment will be made to reflect
collections that will be received at the existing tariff rate from the end
of the month preceding the date of calculation through the end of the month
in which the new tariff is in effect.
PG&E also requests authority to implement a quarterly threshold to be
used only if actual debt service payments fluctuate more than a specified
percent (which may be as low as 2 percent) from the amortization schedule,
so that the FTA charge can be adjusted to better match the scheduled RRB
repayment. If upon quarterly review the threshold is reached, PG&E will
file a True-Up Mechanism Advice Letter no later than 15 days before the end
of the next calendar quarter to make the foregoing adjustment to the FTA
charge. For administrative ease, PG&E proposes to link the true-up dates to
each calendar quarter. The revised FTA charges provided by these True-Up
Mechanism Advice Letter filings would then be effective on the first day of
the following calendar quarter.
PG&E also requests that the Commission grant PG&E authority to make
non-routine True-Up Mechanism Advice Letter filings to be filed no later
than 90 days before the end of any quarter incorporating changes not
specified above to the model, if necessary to meet scheduled RRB
repayments. If this were the case, PG&E requests the Commission make the
new FTA charge changes effective at the beginning of the next calendar
quarter.
In addition to the routine and non-routine true-ups stated above, AB
1890 has stipulated that the Commission shall determine, on each Finance
Order issuance anniversary, whether adjustments to the FTA charge are
required, with any resulting adjustments to the FTA charge to be
implemented within 90 days of issuance anniversary (P.U. Code (S)841(e)).
PG&E expects to comply with the statute by filing a True-Up
6-6
<PAGE>
Mechanism Advice Letter 15 days before each Finance Order issuance
anniversary but expects to state that these true-ups are unnecessary given
the annual and quarterly true-up mechanisms.
Since it is important that the RRBs have the highest possible credit
rating, PG&E requests that these true-up mechanisms not be subject to
litigation or reasonableness review to ensure promptness and timely
adjustments. Failure to implement such standards could harm the RRBs'
possibility of receiving the highest possible credit rating.
During the rate freeze period, modifications to the FTA charge will
not affect the total rate paid by residential and small commercial
customers. However, after the rate freeze period, the FTA charge will
increase or decrease rates paid by residential and small commercial
customers. These periodic FTA charge adjustments are necessary to minimize
variance from the RRB amortization schedule, and to provide adequate
assurance of payment in full of the RRBs, which is a condition for a high
credit rating.
6-7
<PAGE>
TABLE 7-1
ELIGIBLE ELECTRIC RATE SCHEDULES FOR
THE 10 PERCENT DISCOUNT
ON JANUARY 1, 1998
<TABLE>
<CAPTION>
================================================================================
Residential Schedules
================================================================================
<S> <C>
E-1 Residential Service
EL-1 Residential CARE Program Service
EE Service to Company Employees
EM Master-Metered Multifamily Service
EML Master-Metered Multifamily CARE Program Service
ES Multifamily Service
ESL Multifamily CARE Program Service
ESR Residential RV Park and Residential Marina Service
ESRL Residential RV Park and Residential Marina CARE Program
Service
ET Mobilehome Park Service
ETL Mobilehome Park CARE Program Service
E-7 Residential Time-of-Use Service
EL-7 Residential CARE Program Time-of-Use Service
E-A7 Experimental Residential Alternate Peak Time-of-Use
Service
EL-A7 Experimental Residential CARE Program Alternate Peak
Time-of-Use Service
E-8 Residential Seasonal Service Option
EL-8 Residential Seasonal CARE Program Service Option
E-9 Experimental Residential Time-of-Use Service for Low
Emission Vehicle Customers
E-SEG Residential Solar Electric Generating Facility Service
- --------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
================================================================================
Small Commercial Schedules
================================================================================
<S> <C>
A-1 Small General Service
AL-1 Small CARE Program Service
A-6 Small General Time-of-Use Service
AL-6 Small CARE Program General Time-of-Use Service
A-10 (under 20 kW)* Medium General Demand-Metered Service
AL-10 (under 20 kW)* Medium CARE Program General Demand-Metered Service
E-19V (under 20 kW)* Voluntary Medium General Demand-Metered Time-of-Use
Service
EL-19V (under 20 kW)* Voluntary Medium CARE Program General Demand-Metered
Time-of-Use Service
- --------------------------------------------------------------------------------
</TABLE>
*Applicability of the below-20 kW cutoff will be based on the customer's maximum
billing demand which must be less than 20 kW for at least 9 billing periods
during the most recent 12-month period. The applicability of the discount for
these customers shall be assessed on a one-time basis.
6-8
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
APPENDIX A
DESCRIPTION OF SIZING MODEL
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
APPENDIX A
DESCRIPTION OF SIZING MODEL
A. INTRODUCTION
------------
The purpose of this appendix is to present a line-by-line explanation
of the spreadsheet sizing model PG&E uses to: (1) calculate the revenue
requirement necessary to determine the size of the RRB issuance, and (2)
calculate the customer benefits derived from the 10 percent rate reduction
during the rate freeze period and the issuance of the RRBs. The remainder
of this appendix is organized as follows:
Section B discusses the sizing of the RRBs including:
1. Target Residential and Small Commercial Customer Revenue
Reduction
2. Gross Avoided Revenue Requirements
3. RRB Debt Service Revenue Requirements
4. Net Change in Revenue Requirements
5. Customer Benefits
Section C discusses the use of a generic transition cost to size the RRBs.
B. SIZING OF THE RATE REDUCTION BOND ISSUANCE
------------------------------------------
1. Target Residential and Small Commercial Customer Revenue Reduction
------------------------------------------------------------------
The first step in determining the size of the RRBs (i.e., the
amount of Financed Transition Costs) is to convert the target 10
percent rate reduction into a target revenue requirement reduction.
Table 4-A, page 1, lines 1-8 present the total forecasted residential
and small commercial revenue reduction due to the 10 percent rate
reduction for these customer groups over the rate freeze period. The
derivation of this target revenue reduction forecast is described
below.
PG&E multiplies residential rates as of June 10, 1996 by forecast
residential electric sales for each month from January 1998 through
March 2002 to derive the
A-1
<PAGE>
forecast of revenue from residential customers without the 10 percent
rate reduction. In the same manner, PG&E multiplies small commercial
rates as of June 10, 1996 by forecast small commercial electric sales
for each month from January 1998 through March 2002 to derive the
forecast of revenue from small commercial customers without the 10
percent rate reduction. An explanation of the electric sales forecast
is presented in Appendix B of this filing./1/
Next, the forecasts of revenue from residential customers without
the 10 percent rate reduction and of revenue from small commercial
customers without the 10 percent rate reduction are summed to derive
the forecast of total revenue from these customer groups without the
10 percent rate reduction.
Then, PG&E multiplies the forecast total revenues by 10 percent
to determine the forecasted monthly residential and small commercial
revenue reduction due to the 10 percent rate reduction for these
customer groups. The monthly forecasts are summed for each of the
years 1998 through 2001 and then divided by four to derive the
quarterly target revenue reductions for the first 16 quarters of the
rate freeze period. The monthly forecasts for the first quarter of
2002 are summed to derive the target revenue reduction for the last
quarter of the rate freeze period. These forecasted quarterly target
revenue reductions for the 17 quarters ending March 31, 1998 through
March 31, 2002 are presented in Table 4-A, page 1, line 7. Finally,
PG&E takes the sum of these forecasted quarterly revenue reductions,
equal to $1.781 billion (Table 4-A, p. 1, line 8), and uses this
figure as the target revenue reduction in its sizing model.
The following sections describe the assumptions underlying the
gross avoided revenue requirements and RRBs debt service revenue
requirements as presented in Table 4-A, which presents the results of
the model after the iterative process of
___________________________________
/1/ This forecast is consistent with the 1998 sales forecast PG&E presented in
its supplementary testimony to the Cost Separation filing filed on
February 14, 1997 (A.96-12-009).
A-2
<PAGE>
solving for the amount of transition costs that must be financed with
the RRBs in order to achieve the target revenue reduction of $1.781
billion has been completed.
2. Gross Avoided Revenue Requirements
----------------------------------
The gross amount of revenue requirements avoided by financing
transition costs with the RRBs can be broken down into two categories:
(1) the transition cost revenue requirements that PG&E would have
collected from residential and small commercial customers over the rate
freeze period in the absence of the RRB financing, and (2) the carrying
cost savings attained by financing income taxes. This section describes
both of these avoided revenue requirements. It is important to note
that in calculating the avoided revenue requirements, PG&E assumes that
utility debt, preferred stock, and common equity are reduced in
proportions that will maintain the authorized utility capital
structure.
PG&E's assumptions relating specifically to the transition cost
revenue requirements that PG&E would have collected over the rate
freeze period in the absence of the RRB financing are presented in
Table 4-A, page 1. The amortization period for transition costs is four
years and one quarter, from January 1, 1998 through March 31, 2002
(line 12). The authorized pre-tax rate of return on transition costs is
9.65 percent (line 15), calculated using PG&E's 1997 authorized costs
of capital and capital structure, as follows:
<TABLE>
<CAPTION>
Tax Weighted
Component Cost Weight Multiplier Cost
- --------------- --------- --------- ------------ ----------
<S> <C> <C> <C> <C>
Long-term Debt 7.52% 46.2% 1.00 3.47%
Preferred Stock 7.04% 5.8% 1.69 0.69%
Common Equity 6.77% 48.0% 1.69 5.49%
----------
Weighted Average 9.65%
</TABLE>
A-3
<PAGE>
The cost of common equity of 6.77 percent is equal to 90 percent of
the 7.52 percent cost of long-term debt, with the preferred stock and
common equity costs grossed up for income taxes which is authorized only
for transition costs. Franchise fees and uncollectibles are assumed to be 2
percent of revenues (line 17).
The revenue requirements avoided by financing transition costs are
presented in Table 4-A on page 2, lines 18 through 23. PG&E assumes that
the Financed Transition Costs are sunk costs that can be characterized, in
balance sheet terms, as a "Transition Cost-Rate Base Balance" (line 4). The
revenue requirements associated with the transition costs are like those
for other sunk costs: they consist of depreciation (line 5); a pre-tax
return (9.65 percent) on the average rate base balance (line 7); income
taxes (grossed up for tax-on-tax) (line 13); and franchise fees and
uncollectibles (shown quarterly on line 22). The Financed Transition Costs
are equal to the sum of the "Transition Cost-Rate Base Balance" (line 4,
column labeled 12/31/97) and the financed taxes (line 12, column labeled
12/31/97)./2/ These are the avoided transition cost revenue requirements
that PG&E would have collected over the rate freeze period in the absence
of the RRB financing.
There are also revenue requirements that are avoided because of the
RRB financing. These avoided revenue requirements are presented in Table 4-
A, pages 3-5, lines 16-21. The RRB size is based on gross-of-tax transition
costs (see Section C, Use of A Generic Transition Cost of this appendix).
This means that the RRB proceeds include, up front, amounts sufficient to
pay the income taxes associated with the RRB debt service revenue
requirement that will be collected from customers over the term of the
RRBs. Therefore, the FTA charge will not be grossed up for income taxes.
______________________________
/2/ The size of the RRB issued will not exactly equal the amount of transition
costs financed (as defined here) because the issuance amount will also
include bond transaction costs.
A-4
<PAGE>
PG&E assumes that the RRB financing will be a debt-for-tax
transaction./3/ Thus, these income taxes will not be paid immediately, but
instead will be paid over the life of the RRBs, in proportion to the
amortization of the RRB principal. Therefore, given that: (1) PG&E
collects, up front, through the RRB proceeds, enough cash to pay the taxes,
and (2) the cash tax payments will occur over the life of the RRBs, PG&E
will provide customers with a credit equal to the carrying cost savings in
each year. This amount is equal to the unused balance of this cash (Table
4-A, pp. 3-5, line 18) multiplied by the appropriate percentage carrying
cost for each year (the reduced transition cost authorized pre-tax rate of
return of 9.65 percent for the rate freeze period, and the fully authorized
pre-tax rate of return of 13.56 percent for post-rate freeze period, when
there are no more sunk transition costs upon which to apply the lower
return). As the cash is used to pay taxes over the life of the RRBs, the
unused balance of this cash, and therefore the carrying cost credit, will
decline as the RRB debt service revenue requirement is collected. (Since
taxes have been collected, through the RRB proceeds, in advance of paying
them, this calculation is somewhat analogous to the rate base credit given
for normalized deferred taxes.)
The calculation of this carrying cost credit is shown in Table 4-A,
pages 3-5, lines 16-21, with the results summarized on page 3-5, line 29.
These carrying cost credits for the rate freeze period increase the amount
of gross avoided revenue requirements for the rate freeze period and
therefore decrease the amount of RRBs that need to be issued in order to
achieve the target net revenue reduction. The carrying cost credits for the
post-rate freeze period will be passed to customers
_______________________________
/3/ With debt-for-tax treatment, the RRB proceeds will not be treated as
taxable income at the time of the transaction. However, in subsequent
years the revenue received through the FTA charge to make principal
payments on the RRBs will be treated as taxable income.
A-5
<PAGE>
through an explicit ratemaking credit, separate from the RRB debt service
revenue requirement.
Table 4-A, page 1, line 42 and page 6, line 14 present the amount of
transition costs ($3.069 billion, which excludes RRB issuance costs) that
need to be financed in order to avoid the revenue requirements shown on
page 2, line 23, and on pages 3-5, line 29. Because the model solves for
this amount of transition costs, this is also the amount of Financed
Transition Costs needed to achieve the $1.781 billion revenue reduction
shown on page 1, line 8 and page 6, line 12.
3. RRB Debt Service Revenue Requirements
-------------------------------------
PG&E's assumptions relating specifically to the RRB debt service
revenue requirements are presented in Table 4-A, page 1: constant, level
principal amortization (line 33); an amortization period of 10 years, from
1998 through 2007 (line 21): an annualized interest rate of 7.5 percent
(line 25); annual refundable ongoing costs/fees (e.g., servicing fees)
equal to 1.50 percent of the original RRB principal (line 27); annual non-
refundable ongoing costs/fees of $110,000 (line 29); and associated bond
issuance expenses of $25 million (line 36). The resulting quarterly revenue
requirements for RRB debt service and fees for the years 1998 through 2007,
based on these assumptions, are presented in Table 4-A, pages 3-5, lines 4-
8. In addition, the revenue requirement associated with the RRBs will
include franchise fees and uncollectibles (shown quarterly on Table 4-A,
pages 3-5, line 31).
The annualized interest rate is assumed to include interest on the
bonds only, and to exclude ongoing costs/fees. The ongoing administrative
costs that will not be refunded to customers are estimated to be $110,000
(see Chapter 3, Section E for a description of these estimated costs). The
annualized interest rate and non-refundable ongoing costs and fees impact
the sizing of the RRB issuance in the same
A-6
<PAGE>
way; to the extent that they are higher (lower) than currently estimated,
the size of the RRB issuance will be larger (smaller) than currently
estimated.
Ongoing RRB costs and fees that will be refunded to customers are
included in the RRB sizing calculation as both a debit (Table 4-A, pp. 3-5,
line 6) and a credit (line 12) for customers because the refundable amounts
will be captured in the imputed revenue to the CTC Revenue Account during
the rate freeze period, which will in effect offset this part of the FTA
charge (see Chapter 5, Section E.1). Thus, the RRB revenue requirement will
not be affected by these refundable ongoing costs and fees. Therefore, the
size of the RRB issuance will not be affected by these refundable ongoing
costs and fees.
Note that the assumption of constant, level principal amortization
results in an overall RRB annual debt service (principal and interest)
revenue requirement that declines over the amortization period, from $532
million in 1998 to $324 million in 2007.
4. Net Revenue Requirement Reduction
---------------------------------
The calculated quarterly net change in revenue requirements for
residential and small commercial customers is shown in Table 4-A, pages 6-
8, line 8. This is the change in revenue requirements compared to the case
without a 10 percent rate reduction and without the issuance of the RRBs.
For the rate freeze period, the net change is a reduction in the revenue
requirement, the sum of which equals the $1.781 billion target revenue
reduction, as shown in Table 4-A, page 6, line 12. This "result" for the
rate freeze period is actually pre-determined, in that the model iterates
on the amount of Financed Transition Costs (RRB size) in order to achieve
this result. For the post-rate freeze period, the net change is an increase
in the revenue requirement (again, relative to the case without a 10
percent rate reduction and without the issuance of the RRBs). The estimated
size of the RRB issuance is $3.094 billion.
A-7
<PAGE>
5. Customer Benefits
-----------------
The customer benefits derived from the 10 percent rate reduction for
the rate freeze period, coupled with revenue requirement for RRB debt
service for the post-rate freeze period (once again, relative to the case
without a 10 percent rate reduction and without the issuance of the RRBs)
are expressed in present value terms in Table 4-A, page 6, line 20. The
quarterly differences in revenue requirements used to calculate the
customer benefits are shown in Table 4-A, pages 6-8, line 8. Using a
quarterly discount rate of 2.5 percent, the present value (as of December
31, 1997) of the customer benefits is estimated to be $469 million. A
summary of the annual differences in revenue requirements is shown in Table
A-1 at the end of this appendix.
C. USE OF A GENERIC TRANSITION COST
--------------------------------
PG&E uses a generic transition cost in its RRB sizing spreadsheet
model (see Table 4-A, p. 1, line 40). The RRBs are being issued in order to
securitize a portion of PG&E's transition costs, through the creation and
sale of Transition Property. The Transition Property does not consist of,
nor is it linked to, any specific asset or set of assets. Instead, the
Transition Property is linked to the revenues based on the FTA charge.
Therefore, the creation of Transition Property can be based upon any
transition cost as defined by AB 1890.
The effect of the RRB issuance is to reduce the carrying cost on the
transition costs to a rate below the rate of return allowed for uneconomic
assets. For every dollar of Financed Transition Costs, residential and
small commercial customers will pay an interest rate on the RRBs (currently
estimated at 7.5 percent) instead of the authorized pre-tax rate of return
on transition costs (9.65 percent based on PG&E's 1997 authorized cost of
capital and capital structure). Using a generic transition cost with an
authorized pre-tax rate of return of 9.65 percent (rather than using
specific transition cost assets with
A-8
<PAGE>
specific amortization periods, tax characteristics, and associated rates of
return) enables customers to receive the maximum credit for the reduced
carrying cost.
In addition, PG&E will adjust the total amount of transition costs for
the amount of Financed Transition Costs, rather than adjusting specific
asset classes. If specific assets are removed from the transition cost
account, small or large customers could be treated unfairly, depending upon
the assets that are removed. PG&E's CTC account will track when all
customer groups have finished paying their share of transition costs
excluding exemptions. This calculation assumes RRBs were not issued and the
10 percent rate reduction was not provided.
Table 4-A, page 1, line 40, shows the two components of the generic
transition cost that PG&E uses in its RRB sizing spreadsheet model: the Net
Assets, or Rate Base, component equal to $1.819 billion, and the Financed
Taxes component equal to $1.251 billion. The Net Asset (Rate Base)
component represents a generic sunk transition cost. The Financed Taxes
component represents the amount of revenue requirement for income taxes
associated with the revenue requirement for amortization of the Net Asset.
Therefore, the Financed Taxes amount equals the Net Assets multiplied by
the combined federal and state income tax rate,/4/ divided by one minus the
combined federal and state income tax rate.
The avoided transition cost revenue requirements associated with the
two components of the generic transition cost (i.e., the revenue
requirement that PG&E would have collected over the rate freeze period in
the absence of the RRB financing) are shown in Table 4-A, page 2. The
carrying costs savings attained by financing income taxes are shown in
Table 4-A, pages 3-5, lines 16-21 (see Section B.2, Gross Avoided Revenue
Requirements of this appendix).
______________________________
/4/ PG&E uses a combined federal and state income tax rate of approximately
40.75 percent, assuming a federal income tax rate of 35.00 percent and a
state income tax rate of 8.84 percent.
A-9
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
APPENDIX B
ELECTRIC SALES FORECAST
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
APPENDIX B
ELECTRIC SALES FORECAST
A. INTRODUCTION
------------
This appendix explains the development of the January 1998-March 31,
2002 electric sales forecast for use in this RRB application.
B. ELECTRIC SALES FORECAST METHODOLOGY
-----------------------------------
PG&E's electric sales forecast is based on a combination of short- and
long-term forecasting models. The short-term forecasting models are
econometric models used to project sales for the period from 1997 through
1998. These models have provided the basis for the sales forecasts that
have been adopted by the Commission in the last five Electric Cost
Adjustment Clause (ECAC) proceedings./1/ Econometric models are a means of
representing economic behavior through statistical methods such as
regression analysis. The models have been updated with an additional four
quarters of recorded data where appropriate. Model specifications have been
altered only to include trend variables, representing efficiency
improvements, where such variables are statistically significant. PG&E
develops econometric models to forecast electric sales for the residential,
small light and power, and medium light and power customer classes. The
short-term electric sales forecast for the residential, small light and
power, medium light and power, and interdepartmental customer classes for
the year 1998 is identical to the forecast PG&E filed in its supplemental
testimony to the Cost Separation application filed on February 14, 1997
(A.96-12-009) in accordance with the Administrative Law Judge's January 31,
1997, Ruling on Schedule, Scope, and Other Procedural Matters.
________________________
/1/ The last sales forecast adopted by the Commission was in PG&E's 1997 ECAC
(D.96-12-080).
B-1
<PAGE>
Both reflect the 10 percent rate reduction for residential and some small
customers as proposed in this proceeding.
The long-term models are used to forecast sales for the period from 1999
through March 31, 2002. They are end-use models as required by the California
Energy Commission's (CEC) Common Forecasting Methodology (CFM) process. Such
models explicitly forecast energy consumption by end-uses such as lighting,
heating, etc.
For the residential sector, energy consumption is the product of the total
number of households in the PG&E service area, average appliance saturations,
and average unit energy consumption (UEC) by end-use. The appliance saturations
are adjusted over time for the marginal saturations in new homes. Appliance
replacement rates and efficiency rates of new appliances are accounted for in
the UEC calculations. Adjustments for additional conservation savings and
appliance utilization are also accounted for in the model.
For the small light and power and medium light and power sectors, energy
consumption is the product of floor space (organized by building type and
climate area), average end-use equipment saturation and average unit energy
consumption by end-use (Energy Utilization Index or EUI). The end-use equipment
saturations are adjusted over time for the marginal saturations in new
buildings. Equipment replacement rates and efficiency rates of new equipment are
accounted for in the EUI calculations. Adjustments for additional conservation
savings and equipment utilization are also accounted for in the model.
PG&E utilizes DRI/McGraw Hill (DRI) to produce economic and demographic
forecasts. The most recent DRI regional economic forecast (September 1996) was
used to drive PG&E's electric sales forecast of both the short- and long-term
models of the residential, small light and power, and medium light and power
sectors.
B-2
<PAGE>
The electric sales forecast, shown on Table 1 below, has been updated to
reflect the 10 percent rate reduction for residential and some small light and
power and medium light and power customers as proposed in this proceeding.
The forecasted weather related drivers assume normal weather conditions.
Normal weather conditions imply a twenty-year average for such weather drivers
as heating and cooling degree days.
TABLE 1
SALES IN GWHS
<TABLE>
<CAPTION>
Small Light Medium Light
Year Residential and Power and Power Interdept
- ----------- ----------- ---------- ------------- ---------
<S> <C> <C> <C> <C>
1997 25,785 6,958 20,835 152
1998 26,535 7,267 21,132 152
1999 26,850 7,345 21,560 152
2000 27,197 7,427 21,991 153
2001 27,529 7,481 22,326 153
2002 (1st Q) 7,202 1,779 5,279 38
</TABLE>
C. COST SEPARATION DECISION
------------------------
PG&E's sales forecast for the years 1997 through 1998 is the same
forecast filed in the Cost Separation filing (A.96-12-009). If the
Commission adopts PG&E's forecast in that forum, PG&E proposes that the
sales forecast for the years 1997 through 1998 be adopted for purposes of
the RRB application. If the Commission should adopt an alternative sales
forecast for the residential, small light and power, medium light and
power, and interdepartmental customer classes in that proceeding, PG&E
proposes that the Commission use that forecast through 1998 and extend the
forecast through March 31, 2002 by adding the forecasted incremental
customer class changes, filed by PG&E in this forum, to the adopted 1998
forecast year.
B-3
<PAGE>
For example, the 1998 forecast of small light and power sales is 7,267 GWhs
and the incremental change forecast for 1999 is 78 GWhs (7,345-7,267). If the
Commission should adopt a small light and power sales forecast of 7,400 GWhs in
the Cost Separation filing, PG&E recommends that the Commission adopt a forecast
of 7,478 GWhs (7,400+78) for the year 1999 for purposes of the RRB application.
Similarly for other years and other customer classes. PG&E also recommends that
the adopted annual forecasts be allocated to monthly forecasts using the
allocation factors contained in PG&E's recommended sales forecasts.
B-4
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
APPENDIX C
PRO FORMA PRELIMINARY STATEMENT LANGUAGE
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
APPENDIX C, PART 1
RATE REDUCTION BOND ENTRY TO CTC REVENUE ACCOUNT
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
APPENDIX C, PART 1
RATE REDUCTION BOND ENTRY TO REVENUE ACCOUNT
The following entries replace item 6.A.2 on page 5 of PG&E's CTC
Ratemaking Mechanism Tariff Language, submitted on January 13, 1997 (A.96
-08-070). The purpose of these entries is to recognize the revenue
associated with the Rate Reduction Bonds in the CTC Revenue Account. (The
full CTC Tariff language will be submitted on June 16, 1997 for the CTC
Ratemaking Mechanism, as ordered by D.__-___-__.)
6.A.2. A monthly credit entry equal to the Ten Percent Rate Reduction
Amount as defined in Part ZZZ of this preliminary statement (Rate
Reduction Bonds Memorandum Account).
6.A.3. A monthly credit entry equal to the monthly revenue received from
residential and small commercial customers from the Fixed
Transition Amount charge, as provided for in D. __-__-__ and
defined in Part XXXX of this Preliminary Statement.
C-1
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
APPENDIX C, PART 2
PART ZZZ RATE REDUCTION BOND MEMORANDUM ACCOUNT
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
APPENDIX C, PART 2
PART ZZZ RATE REDUCTION BOND MEMORANDUM ACCOUNT
1. Purpose
-------
The purpose of the Rate Reduction Bond Memorandum Account is to record
the difference between the Rate Reduction Bond Savings Amount and the
10 Percent Rate Reduction Amount provided to the residential and small
commercial customers in accordance with AB 1890. This account will
determine whether it is necessary for PG&E to issue additional Rate
Reduction Bonds or to provide a credit to residential and small commercial
customers after the rate freeze period over the remaining life of the Rate
Reduction Bonds. The Rate Reduction Bond Memorandum Account will also track
other credits that may be given to residential and small commercial
customers after the rate freeze period, as defined in Part XXX of this
Preliminary Statement.
2. Applicability
-------------
The Rate Reduction Bond Memorandum Account shall apply to all rate
schedules as identified in Part XXX of this Preliminary Statement.
3. Reduction Bond Memorandum Account Credit Rate
---------------------------------------------
There is currently no rate component. However, a credit rate shall be
established after the end of the rate freeze period to amortize the balance
in this account over the remaining life of the Rate Reduction Bonds.
4. Definitions
-----------
4.A. Rate Reduction Bonds: Rate Reduction Bonds are authorized by the
Commission in D.__-___-__ to provide the funds necessary to allow for
the 10 percent rate reduction in accordance with AB 1890.
C-2
<PAGE>
4.B. Rate Reduction Bond Savings Amount: The Rate Reduction Bond Savings
Amount is equal to the difference between the Fixed Transition Amount
revenue requirement (as defined in Part XXXX of this Preliminary
Statement) and the revenue requirements associated with the portion
of the transition costs that are recovered through the issuance of
the Rate Reduction Bonds, as defined in item 4.A."
4.C. 10 Percent Rate Reduction Amount: The 10 Percent Rate Reduction
Amount is the difference between the residential and small commercial
customer revenues actually billed and the residential and small
commercial customer revenues that would have been billed, based on
frozen rates as of June 10, 1996.
5. Time Period
-----------
The Rate Reduction Bond Memorandum Account will begin January 1, 1998
and will cease after the Rate Reduction Bonds are fully repaid.
6. Accounting Procedures
---------------------
The Rate Reduction Bond Memorandum Account consists of several
memorandum subaccounts. These memorandum subaccounts and the entries made
to these subaccounts are identified below:
6.A. Rate Reduction Bond Proceeds Adjustment Memorandum Subaccount
The following entries shall be made to this subaccount:
6.A.1. A monthly debit equal to Ten Percent Rate Reduction
Amount.
6.A.2. A monthly credit equal to the Rate Reduction Bond
Savings Amount.
6.B. Servicing Fees Memorandum Subaccount
A monthly credit beginning after the rate freeze, equal to the
amount of monthly servicing fees associated with the Rate
Reduction Bonds that
C-3
<PAGE>
are refundable to residential and small commercial customers
after the rate freeze period.
6.C. Carrying Cost Memorandum Subaccount
A monthly credit equal to the interest earned on FTA revenues
held by PG&E.
6.D. SPE Investment Earnings Memorandum Subaccount
A monthly credit equal to the investment earnings on the funds
held by the Bond Trustee after the Bond Trustee returns those to
the SPE./1/
6.E. Overcollateralization Memorandum Subaccount
A credit equal to the FTA charge revenues remitted to the Bond
Trustee and returned to the SPE in excess of the amount needed to
pay the total debt service and other costs associated with the
Rate Reduction Bonds./2/
6.F. Post-Rate Freeze Period Financed Tax Memorandum Subaccount
Beginning after the rate freeze period, a monthly credit equal to
the benefits due to the carrying cost savings of the financed
taxes that occur after the rate freeze period.
The net balance in the Rate Reduction Bond Memorandum Account may be
credited or debited, as appropriate, to residential and small commercial
customers after the rate freeze period.
7. INTEREST
--------
Interest shall accrue on the average of the beginning and ending month
balance in this Rate Reduction Bond Memorandum Account, at a rate equal to
one-twelfth of the interest rate, based on the three-month commercial paper
rate, for the previous month as reported in the Federal Reserve Statistical
Release, G.13. Should
______________________
/1/ These amounts may be distributed to PG&E by the SPE, or result in an
increase in value in PG&E's ownership of the SPE.
/2/ These amounts may be distributed to PG&E by the SPE, or result in an
increase in value in PG&E's ownership of the SPE. In either case, this
amount will be credited.
C-4
<PAGE>
publication of the interest rate on the three-month commercial paper be
discontinued, interest will so accrue at the rate of the one-twelfth of the
previous month's interest rate on commercial paper which most closely
approximates the rate that was discontinued, and which is published in the
Federal Reserve Statistical Release, G.13, or its successor publication.
C-5
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
APPENDIX D
DESCRIPTION OF CASH FLOW MODEL
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
APPENDIX D
DESCRIPTION OF CASH FLOW MODEL
A. INTRODUCTION
------------
The purpose of this appendix is to describe the cash flow model used
to calculate the Fixed Transition Amount (FTA) charge for residential and
small commercial customers.
The remainder of this appendix is organized as follows:
B. Overview of the Rate Reduction Bond (RRB) Cash Flow Model
C. FTA Charge Calculation
B. OVERVIEW OF THE RRB CASH FLOW MODEL
-----------------------------------
The RRB cash flow spreadsheet models the expected interest payments
and principal amortization of the RRBs based on a residential and small
commercial monthly sales forecast from 1998-2007, Bond size, assumed
losses, and ongoing expenses. The model determines the annual FTA charge
for residential and small commercial customers necessary to amortize the
RRBs in equal annual installments over the life of the RRBs assuming
quarterly interest and principal payments.
C. FTA CHARGE CALCULATION
----------------------
The RRB cash flow model will calculate two FTA charges, consisting of
a residential customer FTA charge and a small commercial FTA charge. PG&E
proposes that the RRB amortization schedule will be set such that principal
is payable in equal annual increments over the life of the transaction. The
amortization schedule is designed in this manner in order to provide
ratepayers an annual revenue requirement schedule which declines each year
over the life of the RRB transaction.
The initial FTA charge for each class will be determined as described
below:
. Step 1: Determine monthly sales forecast for residential and small
commercial customers for the years 1998-2007.
D-1
<PAGE>
. Step 2: Determine all components to be covered by FTA collections in
each year 1998-2007. These components include assumptions about RRB
interest, other ongoing expenses, uncollectibles,
overcollateralization, and scheduled principal payments./1/
FTA collections will be remitted monthly and held by the Bond Trustee
in a collection account for distribution on quarterly payment dates. For
purposes of determining the FTA charge, investment earnings on amounts in
the collection account will not be included as part of the collections
available to pay debt service and ongoing expenses.
. Step 3: The sum of all estimated components for each year indicates
the aggregate amount of FTA collections necessary. The sum of the
products of the FTA charge times the usage projections for each
customer class for each year will be calculated to equal the sum of
the components for that year.
12
For each year, the components = SIGMA (CPsc,n *Tsc) +(Pr,n *Tr)
n=l
where n = 1 to 12 months
CPsc,n = monthly usage projection for small commercial
customers
CPr,n = monthly usage projection for residential customers
Tsc = FTA charge for small commercial customers
Tr = FTA charge for residential customers
The FTA charge is solved through an iterative process which solves for
the lowest annual FTA charge which, based on projected monthly sales, will
cover all estimated tariff components for that year. Note that the FTA
charges will be revised to reflect any subsequent issuance of RRBs.
________________________________
/1/ Uncollectible billed FTA revenue and the timing of the remittances
based on servicing procedures and delinquencies will each affect cash
flow available to cover the tariff components and consequently, will
each be factored into the FTA charge as a component.
D-2
<PAGE>
While we know the amount of principal payments payable each year will
be equal to one-tenth of the amount of the financing (for a 10-year cash
flow stream) and we will also have fixed estimates for any other tariff
components which will be assessed as absolute dollar amounts, the amount of
interest payments that will be paid to RRB investors each year will change
based on the quarterly amortization of principal. Expected quarterly
principal payments in each year will be different for each quarter because
a fixed annual charge will be applied to different projected levels of
usage during each quarterly period. Because this amortization rate is based
on the projected usage within each year, the amount of interest payable
each year will depend in part on timing differences caused by seasonal
changes in projected sales.
Table D-1 presents an illustrative forecast of FTA charges for
residential and small commercial customers. It is important to note that
these estimated FTA charges do not reflect certain costs and assumptions
that will be determined at a later date in the servicing agreement, based
on input from the credit rating agencies.
D-3
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
TABLE D-1
ILLUSTRATIVE FIXED TRANSITION AMOUNT (FTA) CHARGE FORECAST/*/
(cents/kWh)
<TABLE>
<CAPTION>
Line Small Line
No. Residential Commercial No.
------ -------------- ------------ ------
<S> <C> <C> <C> <C>
1 1/1/98 1.52 1.71 1
2 1/1/99 1.44 1.62 2
3 1/1/00 1.36 1.52 3
4 1/1/01 1.28 1.44 4
5 1/1/02 1.20 1.35 5
6 1/1/03 1.12 1.26 6
7 1/1/04 1.05 1.18 7
8 1/1/05 0.97 1.09 8
9 1/1/06 0.90 1.01 9
10 1/1/07 0.83 0.94 10
</TABLE>
_____________________
* Note that these FTA charge do not reflect certain costs and assumptions
that will be determined at a later date in the servicing agreement, based,
based on input from the credit rating agencies.
D-4
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
APPENDIX E
PROPOSED FIXED TRANSITION AMOUNT TARIFF LANGUAGE
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
APPENDIX E
PROPOSED FIXED TRANSITION AMOUNT TARIFF LANGUAGE
A. FIXED TRANSITION AMOUNT CHARGE
------------------------------
1. Purpose
-------
The purpose of this section is to establish a Fixed Transition
Amount (FTA) charge for residential and small commercial customers who
receive the 10 percent rate reduction on January1, 1998, as mandated
in Assembly Bill (AB) 1890 (P.U.Code(S)368(a)). AB1890 authorizes
electric utilities to recover a portion of their transition costs
through the issuance of Rate Reduction Bonds (RRBs)
(P.U.Code(S)840(e)). Conditioned upon the issuance of RRBs, AB 1890
requires utilities to reduce rates for residential and small
commercial customers by at least 10percent beginning on January1,
1998, and continuing through the rate freeze period. Residential and
small commercial customers who receive the 10percent rate reduction
(as well as customers in those classes that enter the system after the
rate freeze period) are required to pay the FTA charge. The FTA charge
is defined by AB1890 as a nonbypassable, separate charge that is
authorized by the Commission in a financing order to recover Financed
Transition Costs and the costs of providing, recovering, financing or
refinancing transition costs, including the costs of issuing,
servicing, and retiring RRBs (P.U.Code(S)840(d)). The FTA charge
will be comprised of the following components: (1)scheduled debt
service on the RRBs, (2)servicing fees, (3)Bond Trustee fees,
(4)overcollateralization, (5)allowance for uncollectibles, and
(6)other ongoing expenses.
2. Applicability
-------------
This FTA charge shall apply to all residential and small
commercial electric customers. In addition to customers on SchedulesA-
1 and A-6, customers on
E-1
<PAGE>
Schedules A-10 and E-19V with maximum billing demands of less than
20kW will be classified as small commercial customers. Determination
eligibility will be based on the customer's maximum billing demand,
which must be less than 20kW for at least nine billing periods during
the most recent 12-month period. The applicability of the rate
reduction for these customers shall be determined on a one-time basis.
3. Discount Calculation
--------------------
The 10 percent rate reduction will be applied on January1, 1998,
and continue through the rate freeze period. Bills will be calculated
as usual and a separate line item will be included on the customer's
bill to show the billed amount reduced by 10percent.
4. Issuance Advice Letter
----------------------
PG&E will file an Issurance Advice Letter with the Commission
seeking approval, no less than five business days prior to the close
of the sale of the RRBs, to ensure that FTA revenues from the small
commercial and residential customer classes are sufficient to make the
necessary monthly remittance of the FTA charge to the Bond Trustee.
The Issuance Advice Letter shall include a description of the FTA
charge calculation, the bond issuance amount, identities of one or
more Special Purpose Entities (SPE), identities of one or more
Issuers, and identification of the FTA charge as Transition Property.
5. FTA Charge Adjustments
----------------------
As provided for in P.U. Code(S)841(c), PG&E will file a True-Up
Mechanism Advice Letter one or more times per year to adjust the FTA
charge. The adjustment will be based on the following: (1)the most
recent test-year sales forecast; (2)the test-year projected
amortization schedule; and (3)changes to projected uncollectibles.
The adjustment will be applied such that both the residential and
small commercial FTA charges will be adjusted by the same percentage
increase or decrease.
E-2
<PAGE>
Furthermore, quarterly adjustments will be necessary if actual
debt service payments fluctuate more than X percent from the
amortization schedule. If upon quarterly review the threshold is
reached, PG&E shall file a True-Up Mechanism Advice Letter, to be
approved within 15 days of filing, to revise the FTA charge to be
effective on the first day of the next calendar quarter.
In addition to the annual and quarterly revisions, PG&E may also
make changes to the FTA charge based on changes to the cash flow model
not specified above. In this case, PG&E will file a True-Up Mechanism
Advice Letter no later than 90days before the end of any calendar
quarter and request that the revised FTA charge become effective the
beginning of the next calendar quarter.
In addition to the routine and non-routine true-ups stated above,
AB1890 has stipulated that the Commission shall determine, on each
Finance Order issuance anniversary, whether adjustments to the FTA
charge are required, with any resulting adjustments to the FTA charge
to be implemented within 90days of the issuance anniversary (P.U.
Code(S)841(e)). PG&E expects to comply with the statute by filing a
True-Up Mechanism Advice Letter 15 days before each Finance Order
issuance anniversary but expects to state that these true-ups are
unnecessary given the annual and quarterly true-up mechanisms.
6. FTA Charge
----------
<TABLE>
<CAPTION>
(cents/kWh)
-----------
<S> <C>
Residential Rate Schedules........................... xxx
Small Commercial Rate Schedules...................... xxx
</TABLE>
E-3
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
APPENDIX F
STATEMENT OF QUALIFICATIONS
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF QUALIFICATIONS OF SHELLY S. MALEKOS
Q 1 Please state your name and business address.
A 1 My name is Shelly S. Malekos, and my business address is Pacific Gas and
Electric Company, 77 Beale Street, San Francisco, California.
Q 2 Briefly describe your responsibilities at Pacific Gas and Electric Company.
A 2 I am the director of the electric rates section in the Rates Department. My
section is primarily responsible for preparing presenting the company's
retail electric revenue requirement allocation and rate design proposals
before the California Public Utilities Commission (CPUC).
Q 3 Please summarize your educational and professional background.
A 3 I received a Bachelor of Science degree in Business Administration/Finance
from California State University, Sacramento, in 1984, In 1985, I graduated
from Golden Gate University with a Masters in Business
Administration/Finance.
I joined PG&E as a regulatory affairs analyst in 1985. In 1987, I
joined the cost of service section of the Rates Department as a rates
analyst where I worked on electric marginal cost issues. In 1989, I joined
the QF Contracts Department as a resource analyst where I worked on various
qualifying facility energy and capacity pricing issues. I joined the gas
rates section of the Rates Department in 1990 where I was responsible for
rate-related capacity brokering issues. In 1992, I assumed my current
position.
I have previously sponsored testimony before the CPUC.
Q 4 What is the purpose of your testimony?
A 4 I am sponsoring Chapter 6, "Rate Proposal," Appendix D, "Description of
Cash Flow MOdel," and Appendix E, "Proposed Fixed Transition Amount Tariff
Language," of PG&E's Rate Reduction Bond Financing case.
SSM-1
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF QUALIFICATIONS OF WILLIAM V. MATTSON
Q 1 Please state your name and business address.
A 1 My name is William V. Mattson, and my business address is Pacific Gas and
Electric Company, 77 Beale Street, San Francisco, California
Q 2 Briefly describe your responsibilities at Pacific Gas and Electric
Company.
A 2 I am a senior rates analyst in the risk, revenue and regulatory analysis
section of the Revenue Requirements Department. I am responsible for PG&E's
forecasts of electric sales, revenues and related analyses.
Q 3 Please summarize your educational and professional background.
A 3 I received a Bachelor of Science degree in Business Administration from the
University of Connecticut and a Master of Science degree in Management
Science, with an emphasis in Applied Economics, from the University of
California, Berkeley.
I joined PG&E in 1973, as an engineer trainee in the Generation
Planning Department. I was responsible for developing a weather-sensitive
peak demand model and forecasting peak demand. In 1974, I was promoted to
engineer and continued to be responsible for peak demand forecasting. In
1983, I transferred to the Economics and Statistics Department, where I
supervised a group forecasting the impacts of conservation using large end-
use sales forecasting models. In 1989, I was promoted to senior energy
economist in the Economics and Forecasting Department, responsible for peak
demand and load shape forecasting, and residential and commercial end-use
sales forecasting. In 1993, our section was transferred to the Revenue
Requirements Department. I retained my responsibilities for peak and load
shape forecasting and was given the responsibility for coordinating the
development of PG&E's long-term sales forecasts and developing electric
revenue forecasts.
WVM-1
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF QUALIFICATIONS OF PAUL R. PRUDHOMME
Q 1 Please state your name and business address.
A 1 My name is Paul R. Prudhomme, and my business address is Pacific Gas and
Electric Company, 77 Beale Street, San Francisco, California.
Q 2 Briefly describe your responsibilities at Pacific Gas and Electric Company.
A 2 I am a team leader in the general rate case section of the Revenue
Requirements Department, responsible for the development and presentation
of results of operations calculations in PG&E's various rate cases.
Q 3 Please summarize your educational and professional background.
A 3 I graduated from St. Mary's College in 1970 with a Bachelor of Science
degree in Mathematics. In 1977, I received a Master of Science degree in
Engineering Science with concentration in Industrial Engineering/Operations
Research from the University of California at Berkeley.
I was employed in PG&E's Economics and Statistics Department from 1969
to 1980 as an economic analyst. From 1980 to 1984, I worked in the Rates
Department as supervisor of tariffs in the rate design section. From 1984
to 1993, I worked in the Revenue Requirements Department doing revenue
forecasting and model development. I assumed my current position in
December 1993.
Q 4 What is the purpose of your testimony?
A 4 I am sponsoring the following testimony in PG&E's Rate Reduction Bond
Financing case:
. Chapter 4, "Sizing of the Rate Reduction Bond Issuance,"
. Chapter 5, "Revenue Requirements and Ratemaking Mechanisms,"
. Appendix B, "Description of Sizing Model," and
. Appendix C, "Pro Forma Preliminary Statement Language."
PRP-1
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF QUALIFICATIONS OF MURRAY C. STOLTZ
Q 1 Please state your name and business address.
A 1 My name is Murray C. Stoltz, and my business address is Morgan Stanley &
Co. Incorporated, 1585 Broadway, New York, New York 10036.
Q 2 Briefly describe your responsibilities at Morgan Stanley & Co.
Incorporated.
A 2 I am a principal in the asset finance group within Morgan Stanley's Debt
Capital Markets Divisions. I am responsible for the origination,
structuring, and distribution of asset backed securities transactions, with
a primary focus on working with first-time issuers in the marketplace.
Q 3 Please summarize your educational and professional background.
A 3 I received a Bachelor of Science degree in Industrial Engineering from
Stanford University and a Master of Science degree in Engineering-Economic
Systems from Stanford University, each in 1986.
Upon graduation, I worked as an analyst at Smith Barney on industrial
development bond offerings and tax-exempt issues for corporations including
solid waste disposal and other qualifying facilities. In 1988, I joined the
asset backed securities group at CS First Boston and worked in this group
until 1993. I began my career in the group as an associate and was promoted
to vice president in 1991. At CS First Boston, I focused on the
securitization of automobile, home equity, recreational vehicle, and
motorcycle loans, predominantly for first-time issuers. Between 1993-1995,
I was in the commercial mortgage securitization group at CS First Boston.
In the spring of 1995, I joined the asset finance group of Morgan Stanley
as a vice president and was promoted to principal in 1996. During my tenure
at Morgan Stanley, I have worked on a number of different asset types,
including home equity loans, automobile loans, recreational vehicle loans,
credit card
MCS-1
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF QUALIFICATIONS OF JULIA B. YORK
Q 1 Please state your name and business address.
A 1 My name is Julia B. York, and my business address is Pacific Gas and
Electric Company, 77 Beale Street, San Francisco, California
Q 2 Briefly describe your responsibilities at Pacific Gas and Electric Company.
A 2 I am a project manager in the Finance Department. My responsibilities
include working on special projects for the Vice President-Finance and
Treasurer. Currently, I am project manager for the Rate Reduction Bond
Financing case.
Q 3 Please summarize your educational and professional background.
Q 3 I graduated in 1977 from the University of California at Berkeley with a
Bachelor of Arts degree in Economics. In 1979, I received a Master of
Business Administration degree with an emphasis in Finance from the same
institution. Prior to joining PG&E, my work experiences included five years
in commercial banking, most recently as a lending officer at Chemical Bank
in New York City. In 1981, I joined the PG&E Finance Department. Over the
last nine years, I have held increasingly responsible positions, including
director of financing, director of cash management and Assistant Treasurer.
I became a project manager in July 1994.
Q 4 What is the purpose of your testimony?
A 4 I am sponsoring the following testimony in PG&E's Rate Reduction Bond
Financing case:
. Chapter 1, "Introduction," and
. Chapter 3, "Transaction Overview."
Q 5 Does this conclude your statement of qualifications?
A 5 Yes, it does.
JBY-1
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
APPENDIX G
GLOSSARY
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
APPENDIX G
GLOSSARY
Asset Backed Security A type of fixed income security that is
created by packaging payments underlying a
diverse pool of assets
Bond Trustee An entity (normally, a commercial bank) which
acts on behalf of investors to deposit
collections received by the servicer into the
collection account, invests the deposited
cash in the collection account in highly
rated, liquid investments which mature prior
to distribution dates, distributes principal
and interest payments to bondholders and pays
other ongoing costs associated with the
transaction.
California Infrastructure and Created under the Bergeson-Peace
Economic Development Bank Infrastructure and Economic Development Act,
(Infrastructure Bank) authorized to, among other things, issue and
sell or purchase bonds, as defined, make
loans and provide for other types of
financing for qualifying projects for public
improvements by specified public agencies.
Collection Account The trust account in which the servicer will
deposit collections with respect to the FTA
charge. The collection account is normally
held in the name of the Bond Trustee.
Competition Transition Charge A non-bypassable generation related charge to
(CTC) PG&E's electric customers in order to recover
uneconomic utility investments and
contractual obligations including
re-negotiation or buyout of existing
generation-related contracts.
CTC Revenue Requirement Revenue needed to cover PG&E's CTCs.
CTC Revenues Revenues available to recover CTC revenue
requirement.
Financed Transition Costs The portion of transition costs that electric
utilities will recover through the issuance
of RRBs.
G-1
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
APPENDIX G
GLOSSARY
(Continued)
(TO COME)
G-2
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
APPENDIX G
GLOSSARY
(Continued)
Special Purpose Entity (SPE) A wholly-owned entity organized by PG&E, to
which PG&E will, in the form of a sale,
transfer title to the Transition Property.
The SPE will issue debt securities to the
Issuer.
Transaction Costs Costs associated with the proposed
transaction (includes the following fees:
underwriting, legal, rating agency, SEC
registration, accounting Infrastructure Bank,
and miscellaneous fees).
Transition Costs Costs and categories of costs for generation-
related assets and obligations, consisting of
generation facilities, generation-related
regulatory assets, nuclear settlements, and
power purchase contracts that may become
uneconomic as a result of a competitive
generation market (P.U. Code (S)840 (b)).
Rate Freeze Period January 1, 1998 through March 31, 2002
Transistion Property An irrevocable property right to future non-
bypassable FTAs, the utilities will collect
from residential and small commercial
customers. This right includes the right,
title and interest to all revenues,
collections, claims, payments, money or
proceeds arising from FTAs that are the
subject of a financing order issued by the
Commission (P.U. Code (S)840 (g)).
G-3
<PAGE>
Application No.:
--------------------
Exhibit No.:
------------------------
Date: May 6, 1997
-------------------------------
PACIFIC GAS AND ELECTRIC COMPANY
WORKPAPERS SUPPORTING THE
RATE REDUCTION BOND FINANCING
PG&E LOGO
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
WORKPAPERS SUPPORTING
RATE REDUCTION BOND FINANCING
TABLE OF CONTENTS
<TABLE>
<CAPTION>
CHAPTER TITLE PAGE
------- ----- ----
<S> <C> <C>
6 Rate Proposal SSM-1 - SSM-9
App.B Electric Sales Forecast WVM-0l - WVM-48
</TABLE>
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
EXHIBIT (PG&E-XX) - CHAPTER 7
RATE PROPOSAL WORKPAPERS
<TABLE>
<CAPTION>
PAGE
<S> <C>
WORKPAPER INDEX ssm-1
REVENUE REDUCTION
Estimated 10% Revenue Reduction (1998 - March 2002) ssm-2 ssm-9
Sales Forecast for Residential and Small Commercial Customers (1998 - 2007) ssm-10 ssm-11
</TABLE>
SSM-1
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
1998
ELECTRIC DEPARTMENT ANNUAL
4/8/97 ESTIMATED REVENUE AT 01/01/97 RATES
<TABLE>
<CAPTION>
RATE
REDUCTION
REV CUSTOMER ERAM DISCOUNT CFA
CPUC JURISDICTION ACCT MONTHS SALES REVENUES 10 PERCENT REVENUES
<S> <C> <C> <C> <C> <C> <C> <C>
Line
1 Residential 351 47,599,661 26,534,722,605 1,910,971,232 (317,300,601) 529,422
2 Small Light and Power 352 4,668,303 7,267,158,146 559,258,496 (90,704,976) 145,343
3 Medium Light and Power 353 766,666 21,132,177,297 989,657,120 (3,200,933) 422,644
4 Agricultural 354 1,056,785 3,743,465,000 233,752,131 0 74,869
5 Streetlighting 355 226,954 452,415,998 33,581,098 0 9,048
6 Public Authority 356 468 298,999,992 4,032,116 0 5,980
7 Railway 357 12 15,000,000 951,897 0 300
8 Large Light and Power 359 15,493 17,610,866,549 276,834,425 0 352,217
9 Interdepartmental 360 42,011 152,147,888 6,794,213 (308,926) 3,043
10 Subtotal CPUC Retail 54,596,353 77,206,953,477 4,015,832,728 (411,515,636) 1,542,867
11 Designated Sales 358 12 0 0 0 0
12 Other Operating Revenues (*) 47,377,000 47,377,000 12
13 Total CPUC 54,596,365 77,206,953,477 4,063,209,728 (411,515,636) 1,542,867
Base Fuel
FERC Jurisdiction Revenues Revenues
14 Resale (*) 358 96 38,277,000 2,450,687 0 663,621
15 Other Operating Revenue (*) 47,502,784
16 Total FERC 96 38,277,000 49,953,471 0
17 System Total 54,596,461 77,245,230,477 4,113,163,198 (411,515,636) 1,542,867
18 Total ERAM Revenues 4,015,832,728
Total ESR discount $73,184,772
<CAPTION>
ECAC CPUC FEE CAREA CEE TOTAL AVERAGE
REVENUES REVENUES REVENUES REVENUES REVENUES RATE
<S> <C> <C> <C> <C> <C> <C> <C>
Line Line
1 Residential 1,237,636,096 3,176,533 11,165,131 9,529,598 2,855,707,210 0.10762 1
2 Small Light and Power 344,383,307 872,059 3,270,221 2,616,177 819,840,628 0.11281 2
3 Medium Light and Power 995,647,214 2,535,861 9,509,480 7,607,584 2,002,178,969 0.09475 3
4 Agricultural 166,301,674 449,216 1,684,559 1,347,647 403,610,096 0.10782 4
5 Streetlighting 20,410,324 54,290 0 162,870 54,217,631 0.11984 5
6 Public Authority 13,945,220 3S,880 134,550 107,640 18,261,386 0.06107 6
7 Railway 716,888 1,800 6,750 5,400 1,683,036 0.11220 7
8 Large Light and Power 819,323,178 2,113,304 7,556,133 6,339,912 1,112,519,170 0.06317 8
9 Interdepartmental 7,160,150 18,258 68,467 54,773 13,789,978 0.09064 9
10 Subtotal CPUC Retail 3,605,524,052 9,257,200 33,395,291 27,771,601 7,281,808,103 0.09432 10
11 Designated Sales 0 11
12 Other Operating Revenue (*) 47 ,377,000 12
13 Total CPUC 3,605,524,052 9,257,200 33,395,291 27,771,601 7,329,185,103 0.09493 13
FCA Total
FERC Jurisdiction Revenues Revenues
14 Resale (*) 663,621 3,114,307 0.08136 14
15 Other Operating Revenue (*) 47,502,784 15
16 Total FERC 663,621 1.32239 16
17 System Total 3,606,187,194 9,257,200 33,395,291 27,771,601 7,379,802,194 0.09554 17
18 Total ERAM Revenues 18
(*) Not Subject to ERAM
</TABLE>
SSM-2
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
1999
ELECTRIC DEPARTMENT ANNUAL
ESTIMATED REVENUE AT 01/01/97 RATES
4/8/97
<TABLE>
<CAPTION>
RATE REDUCTION
REV CUSTOMER ERAM DISCOUNT
CPUC JURISDICTION ACCT MONTHS SALES REVENUES 10 PERCENT
<S> <C> <C> <C> <C> <C> <C>
Line
1 Residential 351 48,179,991 26,849,999,999 1,935,104,894 (3,211,205,164)
2 Small Light and Power 352 4,957,859 7,345,000,000 564,938,547 (91,640,467)
3 Medium Light and Power 353 792,492 21,559,999,998 1,013,466,411 (3,312,744)
4 Agricultural 354 1,063,163 3,742,999,999 234,993,592 0
5 Streetlighting 355 236,028 462,000,001 33,975,930 0
6 Public Authority 356 466 241,000,000 4,510,212 0
7 Railway 357 12 16,999,999 973,662 0
8 Large Light and Power 359 15,716 18,124,000,000 285,304,004 0
9 Interdepartmental 360 42,011 152,000,000 6,788,395 (308,668)
10 Subtotal CPUC Retail 55,287,740 78,493,999,996 4,080,055,666 (416,467,042)
11 Designated Sales 358 12 0 0 0
12 Other Operating Revenues (*) 47,377,000
13 Total CPUC 55,287,752 78,493,999,996 4,127,432,666 (416,467,042)
Base Fuel
FERC Jurisdiction Revenues Revenues
14 Resale (*) 358 120 38,962,000 2,403,363 0
15 Other Operating Revenues * 49,502,681
16 Total FERC 120 38,982,000 51,906,044 0
17 System Total 55,287,872 78,532,961,996 4,179,338,710 (416,467,042)
18 Total ERAM Revenues 4,080,055,666
Total ESR discount $75,159,124
<CAPTION>
CFA ECAC CPUC FEE CAREA CEE TOTAL AVERAGE
REVENUES REVENUES REVENUES REVENUES REVENUES REVENUES RATE
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Line Line
1 Residential 535,719 1,252,301,949 3,214,312 11,251,827 9,642,937 2,890,846,474 0.10767 1
2 Small Light and Power 146,900 348,013,077 881,400 3,305,250 2,644,200 828,288,907 0.11277 2
3 Medium Light and Power 431,200 1,016,114,838 2,587,200 9,702,000 7,761,600 2,046,750,506 0.09493 3
4 Agricultural 74,860 166,263,580 449,160 1,684,350 1,347,480 404,813,022 0.10815 4
5 Streetlighting 9,240 20,844,750 55,440 0 166,320 55,051,680 0.11916 5
6 Public Authority 4,820 11,254,190 28,920 106,450 86,760 15,993,352 0.06636 6
7 Railway 340 812,474 2,040 7,650 6,120 1,802,305 0.10602 7
8 Large Light and Power 362,480 843,360,466 2,174,880 7,787,043 6,524,640 1,145,513,514 0.06320 8
9 Interdepartmental 3,040 7,153,134 18,240 68,400 54,720 13,777,261 0.09064 9
10 Subtotal CPUC Retail 3,666,118,458 9,411,592 33,914,971 28,234,777 7,402,837,020 0.09431 10
11 Designated Sales 0 0 11
12 Other Operating Revenues (*) 47,377,000 12
13 Total CPUC 3,666,118,458 9,411,592 33,914,971 28,234,777 7,450,214,020 0.09491 13
FCA Total
Revenues Revenues
14 Resale (*) 676,533 3,079,896 0.07905 14
15 Other Operating Revenues
49,502,681 15
16 Total FERC 676,533 52,582,577 1.34959 16
17 System Total 3,666,794,992 9,411,592 33,914,971 28,234,777 7,502,796,598 0.09554 17
18 Total ERAM Revenues
</TABLE>
* Not Subject to ERAM
SSM-3
<PAGE>
Pacific Gas and Electric Company
Electric Department 2000
4/8/97 Estimated Revenue at 01/01/97 Rates Annual
<TABLE>
<CAPTION>
RATE REDUCTION
REV CUSTOMER ERAM DISCOUNT CFA
CPUC JURISDICTION ACCT MONTHS SALES REVENUES 10 PERCENT REVENUES
<S> <C> <C> <C> <C> <C> <C> <C>
Line
1 Residential 351 48,788,875 27,198,999,997 1,981,373,345 (325,474,0451 542,648
2 Small Light and Power 352 5,017,177 7,427,000,000 570,992,701 (92,633,789) 148,540
,3 Medium Light and Power 353 816,166 21,990,999,999 1,037,168,111 (3,421,044) 439,820
4 Agricultural 354 1,069,144 3,732 000,001 235,959,190 0 74,640
5 Streetlighting 355 246170 473,000,001 34,422,307 0 9,460
6 Public Authority 356 468 325,999,999 4,037,312 0 6,520
7 Railway 357 12 16,999,999 973,682 0 340
8 Large Light and Power 359 15,938 18,600,999,998 293,230,277 0 372,020
9 Interdepartmental 360 42,011 153,000,001 6,829,318 (310,425) 3,060
10 Subtotal CPLIC Retail 55,995,981 79,916,999,995 4,144,986,242 (421,839,303) 1,597,048
11 Designated Sales 358 12 0 0 0 0
12 Other Operating Revenues (*) 47,377,000 47,377,000
13 Total CPUC 55,995,973 79,916,999,995 4,192,363,242 (421,839,303) 1,597,048
Base Fuel
FERC Jurisdiction Revenues Revenues
14 Resale (*) 358 120 39,666,000 2,485,004 0
15 Other Operating Revenues (*) 49,502,681
16 Total FERC 120 39,666,000 51,987,685 0
17 System Total 55,996,093 79,956,665,995 4,244,350,927 (421,839,303) 1,597,048
18 Total ERAM Revenues 4,144,986,242
Total ESR discount $ 77,587,538
(*)Not Subject to ERAM
<CAPTION>
ECAC CPUC FEE CAREA CEE TOTAL AVERAGE
CPUC JURISDICTION REVENUES REVENUES REVENUES REVENUES REVENUES RATE
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Line Line
1 Residential 1,268,450,400 3,255,888 11,350,503 9,767,664 2,929,266,403 0.10771 1
2 Small Light and Power 351,843,817 891,240 3,342,150 2,673,720 837,258,379 0.11273 2
,3 Medium Light and Power 1,036,687,010 2,638,920 9,895,950 7,916,760 2,091,325,527 0.09510 3
4 Agricultural 1 65,757,737 447,840 1,679,400 1,343,520 405,262,327 0.10859 4
5 Streetlighting 21,343,119 56,760 0 170,280 56,001,926 0.11840 5
6 Public Authority 15,199,085 39,120 146,700 117,360 19,546,097 0.05996 6
7 Railway 812,474 2,040 7,650 6,120 1,802,305 0.10602 7
8 Large Light and Power 865,681,241 2,232,120 8,001,693 6,696,360 1,176,213,711 0.06323 8
9 Interdepartmental 7,200,090 18,360 68,850 55,080 13,864,333 0.09062 9
10 Subtotal CPLIC Retail 3,732,974,972 9,582,288 34,492,898 28,746,864 7,530,541,007 0.09423 10
11 Designated Sales 0 0 11
12 Other Operating Revenues (*) 47,377,000 12
13 Total CPUC 3,732,974,972 9,562,288 34,492,898 28,746,864 7,577,918,007 0.09482 13
FCA Total
FERC Jurisdiction Revenues Revenues
14 Resale (*) 689,774 3,174,778 0.08004 14
15 Other Operating Revenues (*) 49,502,681 15
16 Total FERC 689,774 52,677,459 1.32803 16
17 System Total 3,733,664,746 9,582,288 34,492,896 28,746,864 7,630,595,467 0.09543 17
18 Total ERAM Revenues 18
(*)Not Subject to ERAM
</TABLE>
SSM-4
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
2001
ELECTRIC DEPARTMENT ANNUAL
ESTIMATED REVENUE AT 01/01/97 RATES
4/8/97
<TABLE>
<CAPTION>
RATE REDUCTION
REV CUSTOMER ERAM DISCOUNT CFA ECAC
CPUC JURISDICTION ACCT MONTHS SALES REVENUES 10 PERCENT REVENUES REVENUES
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Line
1 Residential 351 49,405,484 27,528,999,999 1,986,270,321 (329,534,466) 549,277 1,283,902,094
2 Small Light and Power 352 5,084,842 7,481,000,000 574,885,990 (93,278,712) 149,620 354,377,898
3 Medium Light and Power 353 831,372 22,326,000,000 1,055,463,951 (3,505,454) 446,520 1,052,717,227
4 Agricultural 354 1,075,151 3,756,000,001 237,682,895 0 75,120 166,788,357
5 Streetlighting 355 248,952 483,000,000 35,203,229 0 9,660 21,818,807
6 Public Authority 356 466 151,000,003 2,389,815 0 3,020 6,983,147
7 Railway 357 12 89,000,001 1,757,928 0 1,780 4,253,536
8 Large Light and Power 359 16,153 18,968,000,002 299,710,094 0 379,360 882,799,467
9 Interdepartmental 360 42,011 153,000,001 6,829,318 (310,425) 3,060 7,200,090
10 Subtotal CPUC Retail 56,704,225 80,936,000,007 4,200,193,542 (426,629,057) 1,617,417 3,780,820,625
11 Designated Sales 358 12 0 0 0 0 0
12 Other Operating Revenues (*) 47,377,000 47,377,000
13 Total CPUC 56,704,237 80,936,000,007 4,247,570,542 (426,629,057) 1,617,417 3,780,820,625
Base Fuel FCA
FERC Jurisdiction Revenues Revenues Revenues
14 Resale (*) 358 120 39,666,000 2,489,204 0 689,774
15 Other Operating Revenues (*) 49,502,681
16 Total FERC 120 39,666,000 51,991,885 0 689,774
17 System Total 56,704,357 80,975,666,007 4,299,562,427 (426,629,057) 1,617,417 3,781,510,399
18 Total ERAM Revenues 4,200,193,542
Total ESR discount $78,728,018
<CAPTION>
CPUC FEE CAREA CEE TOTAL AVERAGE
REVENUES REVENUES REVENUES REVENUES RATE
<S> <C> <C> <C> <C> <C> <C>
Line
1 Residential 3,295,664 11,440,309 9,886,993 2,985,810,193 0.10773 1
2 Small Light and Power 897,720 3,366,450 2,693,160 843,092,126 0.11270 2
3 Medium Light and Power 2,679,120 10,046,700 8,037,360 2,125,885,424 0.09522 3
4 Agricultural 450,720 1,690,200 1,352,160 408,039,452 0.10864 4
5 Streetlighting 57,980 0 173,880 57,263,536 0.11850 5
6 Public Authority 18,120 67,950 54,360 9,498,412 0.06289 6
7 Railway 10,680 40,050 32,040 6,096,017 0.06849 7
8 Large Light and Power 2,276,160 8,166,843 6,828,480 1,200,160,404 0.06327 8
9 Interdepartmental 18,360 68,850 55,080 13,864,333 0.09062 9
10 Subtotal CPUC Retail 9,704,504 34,887,353 29,113,513 7,629,707,897 0.09427 10
11 Designated Sales 0 11
12 Other Operating Revenues (*) 47,377,000 12
13 Total CPUC 9,704,504 34,867,353 29,113,513 7,677,064,897 0.09485 13
Total
Revenues
14 Resale (*) 3,178,978 0.08014 14
15 Other Operating Revenues (*) 49,502,681 15
16 Total FERC 52,681,659 1.32813 16
17 System TotaL 9,704,504 34,887,353 29,113,513 7,729,766,556 0.09546 17
18 Total ERAM Revenues 18
</TABLE>
* Not Subject to ERAM
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
PACIFIC GAS AND ELECTRIC COMPANY
2002
ELECTRIC DEPARTMENT ANNUAL
ESTIMATED REVENUE AT 01/01/97 RATES
4/8/97
<TABLE>
<CAPTION>
RATE
REDUCTION
REV CUSTOMER ERAM DISCOUNT CFA
CPUC JURISDICTION ACCT MONTHS SALES REVENUES 10 PERCENT REVENUES
<S> <C> <C> <C> <C> <C> <C> <C>
Line
1 Residential 351 50,029,847 27,888,000,002 2,011,756,792 (84,984,800) 556,420
2 Small Light and Power 352 5,153,016 7,575,000,000 588,277,544 (18,671,272) 151,500
3 Medium Light and Power 353 846,852 22,815,999,998 1072,510,457 (715,389) 456,320
4 Agricultural 354 1,081,187 3,737,000,000 236,821,202 0 74,740
5 Streetlighting 355 251,760 494,000,000 35,804,677 0 9,880
6 Public Authority 356 468 151,000,003 2,389,815 0 3,020
7 Railway 357 12 89,000,001 1,757,928 0 1,780
8 Large Light and Power 359 16,380 19,507,000,000 306,051,917 0 390,140
9 Interdepartmental 360 42,011 153,000,001 6,829,318 (70,137) 3,060
10 Subtotal CPUC Retell 57,421,533 82,410,000,005 4,262,199,651 (104,441,599) 1,646,860
11 Designated Sales 358 12 0 10,569,240 0
12 Other Operating Revenues (*) 47,377,000
13 Total CPUC 57,421,545 82,410,000,005 4,320,145,891 (104,441,599) 1,646,860
Base Fuel
FERC Jurisdiction Revenues Revenues
14 Resale (*) 358 120 39,666,000 7,340,223 0
15 Other Operating Revenues (*) 47,482,317
16 Total FERC 120 39,666,000 54,822,540 0
17 System Total 57,421,665 82,449,666,005 4,374,988,431 (104,441,599) 1,646,860
18 Total ERAM Revenues 4,272,768,891
Total ESR discount $81,058,498
<CAPTION>
ECAC CPUC FEE CAREA CEE TOTAL AVERAGE RATE
CPUC JURISDICTION REVENUES REVENUES REVENUES REVENUES REVENUES REVENUES
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Line Line
1 Residential 1,300,768,806 3,338,522 11,821,230 10,015,565 3,253,272,534 0.11665 1
2 Small Light and Power 359,100,875 909,000 3,408,750 2,727,000 935,903,398 0.12355 2
3 Medium Light and Power 1,075,233,772 2,737,920 10,267,200 8,213,760 2,168,704,040 0.09505 3
4 Agricultural 166,047,204 448,440 1,681,650 1,345,320 406,418,556 0.10876 4
5 Streetlighting 22,284,516 59,280 0 177,840 58,336,193 0.11809 5
6 Public Authority 6,963,147 18,120 67,950 54,360 9,496,412 0.06289 6
7 Railway 4,253,538 10,680 40,050 32,040 6,098,017 0.06849 7
8 Large Light and Power 907,792,507 2,340,840 8,409,393 7,022,520 1,232,007,318 0.06316 8
9 Interdepartmental 7,200,090 18,360 68,850 55,080 14,104,621 0.09219 9
10 Subtotal CPUC Retell 3,849,644,455 9,881,162 35,765,073 29,643,485 8,084,339,087 0.09810 10
11 Designated Sales 0 10,569,240 11
12 Other Operating Revenues (*) 47,377,000 12
13 Total CPUC 3,849,644,455 9,881,162 35,765,073 29,643,485 8,142,285,327 0.09880 13
FCA Total
FERC Jurisdiction Revenues Revenues
14 Resale (*) 689,774 8,029,997 0.20244 14
15 Other Operating Revenues (*) 47,482,317 15
16 Total FERC 689,774 55,512,314 1.39949 16
17 System Total 3,850,334,229 9,861,162 35,765,073 29,843,485 8,197,797,841 0.09943 17
18 Total ERAM Revenues 18
</TABLE>
* Not Subject to ERAM
SSM-6
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY 37257
ELECTRIC DEPARTMENT Monthly
4/8/97 ESTIMATED REVENUE AT 01/01/97 RATES
<TABLE>
<CAPTION>
RATE REDUCTION
REV CUSTOMER ERAM DISCOUNT CFA ECAC
CPUC JURISDICTION ACCT MONTHS SALES REVENUES 10 PERCENT REVENUES REVENUES
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Line
1 Residential 351 4,163,006 2,629,728,765 187,150,789 (31,354,384) 52,469 123,966,322
2 Smell Light end Power 352 429,701 586,028,607 30,555,198 (6,223,757) 11,721 31,412,511
3 Medium Light and Power 353 70,324 1,738,454,004 41,379,659 (238,463) 34,769 92,472,857
4 Agricultural 354 90,213 120,385,412 8,895,020 0 2,408 6,223,548
5 Streetlighting 355 20,932 41,314,625 2,988,818 0 826 1,863,717
6 Public Authority 356 39 10,839,889 32,993 0 217 572,346
7 Railway 357 1 8,872,825 33,772 0 177 473,678
8 Large Light end Power 359 1,397 1,488,813,042 2,508,352 0 29,776 78,274,425
9 Interdepartmental 360 3,501 12,157,630 299,940 (22,553) 243 646,342
10 Subtotal CPUC Retail 4,779,114 6,636,594,799 273,844,538 (37,839,157) 132,807 335,905,746
11 Designated Sales 358 1 0 880,770 0 0
12 Other Operating Revenues(*) 3,948,083
13 Total CPUC 4,779,115 6,636,594,799 278,673,391 (37,839,157) 132,607 335,905,746
Base Fuel FCA
FERC Jurisdiction Revenues Revenues Revenues
14 Resale (*) 358 10 3,040,000 600,937 0 47,935
15 Other Operating Revenues(*) 3,956,860
16 Total FERC 10 3,040,000 4,557,797 0 47,935
17 System Total 4,779,125 6,639,634,799 283,231,188 (37,839,157) 132,607 335,953,681
18 Total ERAM Revenues 274,725,308
Total ESR discount $6,178,985
<CAPTION>
CPUC FEE CAREA CEE TOTAL AVERAGE
CPUC JURISDICTION REVENUES REVENUES REVENUES REVENUES RATE
<S> <C> <C> <C> <C> <C> <C> <C>
Line Line
1 Residential 314,815 1,114,999 944,448 282,189,457 0.10731 1
2 Smell Light end Power 70,323 283,713 210,970 56,300,676 0.09607 2
3 Medium Light and Power 208,614 782,304 625,843 135,265,584 0.07781 3
4 Agricultural 14,448 54,173 43,339 15,232,934 0.12853 4
5 Streetlighting 4,958 0 14,873 4,873,193 0.11795 5
6 Public Authority 1,301 4,878 3,902 615,636 0.05679 6
7 Railway 1,065 3,993 3,194 515,879 0.05814 7
8 Large Light end Power 178,658 844,981 535,973 82,172,165 0.05519 8
9 Interdepartmental 1,459 5,471 4,377 935,279 0.07693 9
10 Subtotal CPUC Retail 795,639 2,874,513 2,386,918 578,100,804 0.08711 10
11 Designated Sales 880,770 11
12 Other Operating Revenues(*) 3,948,083 12
13 Total CPUC 795,639 2,874,513 2,386,918 582,929,657 0.08784 13
Total
FERC Jurisdiction Revenues
14 Resale (*) 648,872 0.21344 14
15 Other Operating Revenues(*) 3,956,860 15
16 Total FERC 4,805,732 1.51504 16
17 System Total 795,639 2,874,513 2,386,918 587,535,389 0.08849 17
18 Total ERAM Revenues 18
</TABLE>
(*) Not Subject to ERAM
SSM-7
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
MONTHLY
ELECTRIC DEPARTMENT FEB-02
4/8/97 ESTIMATED REVENUE AT 01/01/97 RATES
<TABLE>
<CAPTION>
RATE REDUCTION
REV CUSTOMER ERAM DISCOUNT CFA ECAC CPUC FEE
CPUC JURISDICTION ACCT MONTHS SALES REVENUES 10 PERCENT REVENUES REVENUES REVENUES
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Line
1 Residential 351 4,166,762 2,354,699,495 163,543,245 (27,686,128) 46,982 111,140,076 281,890
2 Smell Light end Power 352 428,198 593,337,041 30,878,532 (6,223,757) 11,867 31,805,465 71,200
3 Medium Light and Power 353 70,415 1,760,134,476 41,884,645 (238,463) 35,203 93,632,541 211,216
4 Agricultural 354 90,212 137,505,915 8,951,498 0 2,750 7,108,949 16,501
5 Streetlighting 355 20,953 41,279,751 2,987,617 0 826 1,862,144 4,954
6 Public Authority 356 39 9,241,085 35,621 0 185 488,350 1,109
7 Railway 357 1 8,027,525 36,814 0 161 428,552 983
8 Large Light end Power 359 1,282 1,409,415,124 2,295,214 0 28,188 74,093,615 169,130
9 Interdepartmental 360 3,501 11,412,213 284,714 (21,385) 228 606,713 1,369
10 Subtotal CPUC Retail 4,781,361 6,325,052,625 250,897,899 (34,169,733) 126,389 321,166,405 758,332
11 Designated Sales 358 1 0 880,770 0 0
12 Other Operating Revenues(*) 3,948,083
13 Total CPUC 4,781,362 6,325,052,625 255,728,753 (34,169,733) 126,389 321,168,405 758,332
Base Fuel FCA
FERC Jurisdiction Revenues Revenues Revenues
14 Resale (*) 358 10 3,559,000 597,722 0 65,539
15 Other Operating Revenues(*) 3,956,860
16 Total FERC 10 3,559,000 4,554,582 0 65,539
17 System Total 4,781,372 6,328,611,625 260,281,335 (34,169,733) 126,389 321,231,943 758,332
18 Total ERAM Revenues 251,778,669
Total ESR discount $5,782,545
<CAPTION>
CAREA CEE TOTAL AVERAGE
CPUC JURISDICTION REVENUES REVENUES REVENUES RATE
<S> <C> <C> <C> <C> <C> <C>
Line Line
1 Residential 1,003,423 845,669 249,175,156 0.10582 1
2 Smell Light end Power 267,002 213,601 57,023,910 0.09611 2
3 Medium Light and Power 792,061 633,648 136,950,851 0.07781 3
4 Agricultural 61,876 49,502 18,191,076 0.11775 4
5 Streetlighting 0 14,861 4,870,401 0.11799 5
6 Public Authority 4,158 3,327 532,750 0.05765 6
7 Railway 3,612 2,890 472,992 0.05892 7
8 Large Light end Power 604,874 507,389 77,698,410 0.05513 8
9 Interdepartmental 5,135 4,108 880,884 0.07719 9
10 Subtotal CPUC Retail 2,742,143 2,274,996 543,798,431 0.08598 10
11 Designated Sales 880,770 11
12 Other Operating Revenues(*) 3,948,083 12
13 Total CPUC 2,742,143 2,274,996 548,625,284 0.08674 13
Total
Revenues
14 Resale (*) 663,261 0.18636 14
15 Other Operating Revenues(*) 3,958,860 15
16 Total FERC 4,820,121 1.29815 16
17 System Total 2,742,143 2,274,998 553,245,405 008742 17
18 Total ERAM Revenues 18
</TABLE>
(*) Not Subject to ERAM
SSM-8
<PAGE>
PacIfic Ca: and PACIFIC GAS AND ELECTRIC COMPANY
MONTHLY
ELECTRIC DEPARTMENT MAR-02
4/8/97 ESTIMATED REVENUE AT 01/01/97 RATES
<TABLE>
<CAPTION>
RATE REDUCTION
REV CUSTOMER ERAM DISCOUNT CFA ECAC
CPUC JURISDICTION ACCT MONTHS SALES REVENUES 10 PERCENT REVENUES REVENUES
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Line
I Residential 351 4,177,695 2,217,084,575 152,671,918 (25,944,288) 44,235 104,719,259
2 Small Light and Power 352 430,357 600,425,121 31,226,783 (6,223,757) 12,009 32,186,545
3 Medium Light and Power 353 70,974 1,781,161,267 42,410,654 (238,463) 35,623 94,757,258
4 Agricultural 354 89,872 170,122,789 9,034,298 0 3,402 8,798,227
5 Streetlighting 355 21,055 40,905,624 2,974,734 0 818 1,845,267
6 Public Authority 356 39 12,786,711 29,789 0 256 674,730
7 Railway 357 1 6,208,249 43,363 0 124 331,429
8 Large Light and Power 359 1,418 1,592,186,791 2,580,438 0 31,844 83,706,418
9 Interdepartmental 360 3,501 14,485,713 347,493 (26,200) 290 770,111
10 Subtotal CPUC Retail 4,794,910 6,435,368,840 (241,319,469 32,432,708) 128,601 327,787,245
11 Designated Sales 358 1 0 880,770 0 0 880,770
12 Other Operating Revenues * 3,948,083
13 Total CPUC 4,794,911 6,435,368,840 (246,148,323 32,432,708) 128,601 327,787,245
Base Fuel FCA
FERC Jurisdiction Revenues Revenues Revenues
14 Resale (*) 358 10 4,214,000 601,060 0 78,429
15 Other Operating Revenues(*) 3,956,860
16 Total FERC 10 4,214,000 4,557,920 0 78,429
17 System Total 4,794,921 6,439,582,840 250,706,242 (32,432,708) 128,601 327,865,673
18 Total ERAM Revenues 242,200,239
Total ESR discount $6,585,607
<CAPTION>
CPUC FEE CAREA CEE TOTAL AVERAGE
CPUC JURISDICTION REVENUES REVENUES REVENUES REVENUES RATE
<S> <C> <C> <C> <C> <C> <C> <C>
Line Line
I Residential 265,413 945,816 798,238 233,498,591 0.10532 1
2 Small Light and Power 72,051 270,191 218,153 57,759,974 0.09620 2
3 Medium Light and Power 213,739 801,523 641,218 138,621,553 0.07783 3
4 Agricultural 20,415 76,555 61,244 17,992,141 0.10578 4
5 Streetlighting 4,909 0 14,728 4,840,454 0.11833
6 Public Authority 1,535 5,755 4,604 716,669 0.05804 6
7 Railway 745 2,794 2,235 380,690 0.06132 7
8 Large Light and Power 191,062 687,357 573,187 87,770,306 0.05513 8
9 Interdepartmental 1,738 6,519 5,215 1,105,165 0.07629 9
10 Subtotal CPUC Retail 771,607 2,798,509 2,314,820 542,685,543 0.08433 10
11 Designated Sales 880,770 11
12 Other Operating Revenues * 3,948,083 12
13 Total CPUC 771,607 2,798,509 2,314,820 547,514,398 0.08508 13
Total
FERC Jurisdiction Revenues
14 Resale (*) 679,488 0.16125 14
15 Other Operating Revenues(*) 3,958,860 15
16 Total FERC 4,636,348 1.10022 16
17 System Total 771,607 2,798,509 2,314,820 552,150,744 0.08574 17
18 Total ERAM Revenues 18
</TABLE>
(*) Not Subject to ERAM
SSM-9
<PAGE>
Sales Forecast
Eligible Discount Customers
1998 - 2001 (1000's KWh)
<TABLE>
<CAPTION>
1997 Jan-97 Feb-97 Mar-97 Apr-97 May-97 Jun-97 Jul-97 Aug-97 Sep-97
----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Residential
Individual meter 0 0 0 0 0 0 0 0 0
Master meter 0 0 0 0 0 0 0 0 0
Total 0 0 0 0 0 0 0 0 0
Light & Power
Small 0 0 0 0 0 0 0 0 0
Medium 0 0 0 0 0 0 0 0 0
Inter Departmental 0 0 0 0 0 0 0 0 0
Total disc. Sales 0 0 0 0 0 0 0
1998 Jan-98 Feb-98 Mar-98 Apr-98 May-98 Jun-98 Jul-98 Aug-98 Sep-98
----------------------------------------------------------------------------------------------------
Residential
Individual mater 2,425,895 2,172,183 2,045,235 1,924,287 1,896,349 2,039,463 2,266,929 2,404,385 2,247,102
Master meter 90,050 81,625 76,163 72,324 70,448 74,435 79,847 84,005 80,761
Total 2,515,945 2,253,809 2,121,398 1,996,611 1,966,798 2,113,898 2,346,776 2,488,390 2,327,863
Light & Power
Small 562,130 569,157 575,972 540,798 562,758 603,237 652,746 679,398 679,329
Medium 22,448 22,808 23,156 23,186 21,957 24,051 24,563 25,871 25,906
inter Departmental 1,864 1,750 2,221 1,730 1,625 1,839 1,585 1,652 1,743
Total disc. Sales 3,102,387 2,847,523 2,722,747 2,562,325 2,553,139 2,743,025 3,025,671 3,195,311 3,034,841
1999 Jan-99 Feb-99 Mar-99 Apr-99 May-99 Jun-99 Jul-99 Aug-99 Sep-99
----------------------------------------------------------------------------------------------------
Residential
Individual meter 2,448,402 2,192,337 2,064,211 1,945,874 1,917,623 2,062,342 2,305,112 2,444,884 2,284,952
Master meter 89,316 79,975 75,301 70,984 69,954 75,233 64,089 89,186 83,354
Total 2,537,718 2,272,312 2,139,512 2,016,859 1,987,577 2,137,575 2,389,202 2,534,072 2,368,306
Light & Power
Small 567,585 574,680 581,561 545,844 568,009 608,866 660,961 687,948 687,878
Medium 23,237 23,602 23,956 23,985 22,735 24,868 25,387 26,718 26,752
Inter Departmental 1,862 1,748 2,219 1,728 1,623 1,837 1,584 1,650 1,741
Total disc. Sales 3,130,402 2,872,342 2,747,247 2,588,417 2,579,945 2,773,146 3,077,133 3,250,389 3,084,677
2000 Jan-00 Feb-00 Mar-00 Apr-00 May-00 Jun-00 Jul-00 Aug-00 Sep-00
----------------------------------------------------------------------------------------------------
Residential
Individual meter 2,475,083 2,216,227 2,086,705 1,970,424 1,941,816 2,088,360 2,346,265 2,488,532 2,325,745
Master meter 89,487 60,128 75,445 71,241 70,207 75,505 84,830 89,973 84,088
Total 2,564,570 2,296,356 2,162,150 2,041,665 2,012,023 2,163,865 2,431,095 2,578,506 2,409,833
Light & Power
Small 573,240 580,405 587,355 551,095 573,473 614,722 669,601 696,941 696,870
Medium 23,989 24,359 24,718 24,744 23,472 25,643 26,199 27,555 27,587
Inter Departmental 1,874 1,759 2,233 1,740 1,634 1,849 1,595 1,662 1,753
Total disc. Sales 3,163,673 2,902,879 2,776,456 2,619,244 2,610,601 2,806,080 3,128,490 3,304,663 3,136,043
2001 Jan-01 Feb-01 Mar-01 Apr-01 May-01 Jun-01 Jul-01 Aug-01 Sep-01
----------------------------------------------------------------------------------------------------
Residential
Individual meter 2,506,012 2,243,922 2,112,781 1,995,046 1,966,081 2,114,457 2,375,585 2,519,629 2,354,808
Master meter 89,864 80,466 75,763 71,541 70,503 75,823 85,187 90,352 84,442
Total 2,595,676 2,324,388 2,188,544 2,066,588 2,036,584 2,190,280 2,460,772 2,609,982 2,439,250
Light & Power
Small 577,406 584,624 591,624 555,100 577,641 619,190 674,468 702,006 701,935
Medium 24,612 24,987 25,350 25,375 24,085 26,287 26,850 28,225 28,255
Inter Departmental 1,874 1,759 2,233 1,740 1,634 1,849 1,595 1,662 1,753
Total disc. Sales 3,199,768 2,935,757 2,807,751 2,648,803 2,639,943 2,837,606 3,163,685 3,341,875 3,171,194
<CAPTION>
1997 0ct-97 Nov-97 Dec-97 Total
-------------------------------------------
<S> <C> <C> <C> <C>
Residential
Individual meter 0 0 0 0
Master meter 0 0 0 0
Total 0 0 0 0
Light & Power
Small 0 0 0 0
Medium 0 0 0 0
Inter Departmental
Total disc. Sales
1998 0ct-98 Nov-98 Dec-98 Total
-------------------------------------------
Residential
Individual mater 1,947,478 1,964,682 2,261,307 25,595,297
Master meter 72,413 73,617 83,738 939,426
Total 2,019,891 2,038,299 2,345,045 26,534,723
Light & Power
Small 647,524 596,159 582,158 7,251,365
Medium 24,535 24,542 23,813 286,837
inter Departmental 1,942 1,692 1 647 21,489
Total disc. Sales 2,693,892 2,660891 2,952,663 34,094,413
1999 0ct 99 Nov 99 Dec 99 Total
-------------------------------------------
Residential
Individual meter 1 968 234 1 985621 2,285,407 25,905,000
407
Master meter 71 800 72 434 63 370 945,000
Total 2,040,034 2,058,056 2,366 778 26,850,000
Light & Power
Small 654,580 602,655 588,502 7,329,070
Medium 25,362 25,363 24 616 296,582
Inter Departmental 1,940 1,890 1,645 21,468
Total disc. Sales 2,721,916 2,687,964 2,963,543 34,497,121
2000 0ct-00 Nov-00 Dec-00 Total
-------------------------------------------
Residential
Individual meter 1,990,183 2,007,764 2,310,894 26,248,000
Master meter 71,955 72,591 83,551 949,000
Total 2,062,138 2,080,355 2,394,444 27,197,000
Light & Power
Small 662,201 609,672- 595,354 7,410,931
Medium 26,211 26,207 25,444 306,128
Inter Departmental 1,953 1,902 1,656 21,609
Total disc. Sales 2,752,504 2,718,137 3,016,898 34,935,668
2001 0ct-01 Nov-01 Dec-01 Total
-------------------------------------------
Residential
Individual meter 2,015,053 2,032,854 2,339,771 26,576,000
Master meter 72,259 72,897 83,903 953,000
Total 2,087,311 2,105,751 2,423,674 27,529,000
Light & Power
Small 667,014 614,103 599,681 7,464,792
Medium 26,857 26,848 26,073 313,804
Inter Departmental 1,953 1,902 1,656 21,609
Total disc. Sales 2,783,135 2,748,605 3,051,084 35,329,206
</TABLE>
SSM-10
<PAGE>
Sales Forecast
Eligible Discount Customers
2002 - 2006 (1000's KWh)
<TABLE>
<CAPTION>
2002 Jan-02 Feb-02 Mar-02 Apr-02 Mav-02 Jun-02 Jul-02 Aug-02 Sep-02
----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Individual meter 2,539,487 2,273,896 2,141,003 2,021,696 1,992,344 2,142,702 2,407,318 2,553,286 2,386,263
Master meter 90,241 80,803 76,081 71,841 70,798 76,141 85,545 90,732 84,796
Total 2,629,729 2,354,699 2,217,085 2,093,538 2,063,143 2,218,843 2,492,862 2,644,018 2,471,060
Light & Power
Small 584,724 592,032 599,120 562,138 584,962 627,033 683,005 710,890 710,818
Medium 24,494 24,883 25,262 25,294 23,998 26,256 26,837 28,249 28,285
Inter Departmental 1,874 1,759 2,233 1,740 1,634 1,849 1,595 1,662 1,753
Total disc. Sales 3,240,820 2,973,374 2,843,699 2,682,709 2,673,736 2,873,981 3,204,300 3,384,819 3,211,916
2003 Jan-03 Feb-03 Mar-03 Apr-03 Mav-03 Jun-03 Jul-03 Aug-03 Sep-03
----------------------------------------------------------------------------------------------------
Residential
Individual meter 2,571,077 2,302,181 2,167,636 2,046,844 2,017,127 2,169,355 2,437,263 2,585,047 2,415,946
Master meter 90,619 81,141 76,399 72,142 71,094 76,460 85,902 91,111 85,151
Total 2,661,695 2,383,323 2,244,035 2,118,986 2,088,222 2,245,815 2,523,165 2,676,158 2,501,097
Light & Power
Small 590,824 598,209 605,371 568,003 591,065 633,575 690,131 718,306 718,234
Medium 25,393 25,789 26,173 26,205 24,883 27,186 27,777 29,216 29,251
Inter Departmental 1,874 1,759 2,233 1,740 1,634 1,849 1,595 1,662 1,753
Total disc. Sales 3,279,786 3,009,080 2,877,812 2,714,933 2,705,803 2,908,425 3,242,668 3,425,342 3,250,335
2004 Jan-04 Feb-04 Mar-04 Apr-04 May-04 Jun-04 Jul-04 Aug-04 Sep-04
----------------------------------------------------------------------------------------------------
Residential
Individual meter 2,603,797 2,331,480 2,195,222 2,072,894 2,042,798 2,196,963 2,468,281 2,617,946 2,446,693
Master meter 90,996 81,479 76,717 72,442 71,390 76,778 86,260 91,490 85,505
Total 2,694,793 2,412,959 2,271,939 2,145,336 2,114,188 2,273,741 2,554,540 2,709,436 2,532,198
Light & Power
Small 597,079 604,542 611,780 574,016 597,322 640,282 697,437 725,910 725,837
Medium 26,333, 26,737 27,128 27,159 25,810 28,163 28,765 30,234 30,267
Inter Departmental; 1,874 1,759 2,233 1,740 1,634 1,849 1,595 1,662 1,753
Total disc. Sales 3,320,080 3,045,997 2,913,080 2,748,251 2,738,955 2,944,036 3,282,337 3,467,243 3,290,056
2005 Jan-05 Feb-05 Mar-05 Apr-05 May-05 Jun-05 Jul-05 Aug-05 Sep-05
----------------------------------------------------------------------------------------------------
Residential'
Individual meter 2,637,461 2,361,623 2,223,604 2,099,693 2,069,209 2,225,367 2,500,192 2,651,792 2,478,325
Master meter 91,373 81,817 77,035 72,742 71,686 77,096 86,617 91,869 85,860
Total 2,728,834 2,443,440 2,300,639 2,172,436 2,140,895 2,302,464 2,586,810 2,743,662 2,564,185
Light & Power
Small 604,108 611,658 618,981 580,773 604,354 647,819 705,646 734,455 734,380
Medium 27,365 27,777 28,177 28,207 26,824 29,236 29,851 31,355 31,387
Inter Departmental 1,874 1,759 2,233 1,740 1,634 1,849 1,595 1,662 1,753
Total disc. Sales 3,362,180 3,084,634 2,950,030 2,783,155 2,773,707 2,981,367 3,323,901 3,511,134 3,331,705
2006 Jan-06 Feb-06 Mar-06 Apr-06 May-06 Jun-06 Jul-06 Aug-06 Sep-06
----------------------------------------------------------------------------------------------------
Residential
Individual meter 2,674,142 2,394,468 2,254,529 2,128,895 2,097,987 2,256,317 2,534,964 2,688,673 2,512,793
Master meter 91,750 82,154 77,353 73,043 71,982 77,414 86,975 92,249 86,214
Total 2,765,892 2,476,622 2,331,882 2,201,938 2,169,969 2,333,732 2,621,939 2,780,922 2,599,008
Light & Power
Small 611,523 619,166 626,579 587,902 611,772 655,770 714,307 743,469 743,394
Medium 28,391 28,813 29,222 29,251 27,835 30,307 30,935 32,476 32,506
Inter Departmental 1,874 1,759 2,233 1,740 1,634 1,849 1,595 1,662 1,753
Total disc. Sales 3,407,680 3,126,360 2,989,915 2,820,831 2,811,210 3,021,658 3,368,776 3,558,529 3,376,661
<CAPTION>
2002 0ct-02 Nov-02 Dec-02 Total
---------------------------------------------
<S> <C> <C> <C> <C>
Individual meter 2,041,970 2,060,009 2,371,026 26,931,000
Master meter 72,562 73,203 84,255 957,000
Total 2,114,532 2,133,211 2,455,281 27,888,000
Light & Power
Small 675,458 621,882 607,279 7,559,340
Medium 26,862 26,841 26,055 313,316
Inter Departmental 1,953 1,902 1,656 21,609
Total disc. Sales 2,818,804 2,783,837 3,090,271 35,782,265
2003 Oct-03 Nov-03 Dec-03 Total
---------------------------------------------
Residential
Individual meter 2,067,370 2,085,633 2,400,519 27,266,000
Master meter 72,865 73,509 84,607 961,000
Total 2,140,235 2,159,142 2,485,126 28,227,000
Light & Power
Small 682,505 628,370 613,615 7,638,207
Medium 27,794 27,765 26,961 324,391
Inter Departmental 1,953 t,902 1,656 21,609
Total disc. Sales 2,852,487 2,817,179 3,127,358 36,211,207
2004 Oct 04 Nov-04 Dec 04 Total
---------------------------------------------
Residential
Individual meter 2,093,680 2,112,176 2431069 27,613,000
Master meter 73,168 73 815 84 959 965,000
Total 2,166,849 2,185,991 2,516029 28,578,000
Light & Power
Small 689,730 635,023 620,111 7,719,070
Medium 28,774 28,738 27,914 336,023
Inter Departmental; 1,953 1,902 1,656 21,609
Total disc. Sales 2,887,306 2,851,654 3,165,709 36,654,703
2005 Oct-05 Nov-05 Dec-05 Total
---------------------------------------------
Residential'
Individual meter 2,120,749 2,139,484 2,462,500 27,970,000
Master meter 73,472 74,121 85,311 969,000
Total 2,194,221 2,213,605 2,547,811 28,939,000
Light & Power
Small 697,849 642,498 627,410 7,809,931
Medium 29,852 29,810 28,962 348,801
Inter Departmental 1,953 1,902 1,656 21,609
Total disc. Sales 2,923,874 2,887,814 3,205,840 37,119,342
2006 Oct-06 Nov-06 Dec-06 Total
---------------------------------------------
Residential
Individual meter 2,150,244 2,169,239 2,496,748 28,359,000
Master meter 73,775 74,427 85,664 973,000
Total 2,224,019 2,243,666 2,582,411 29,332,000
Light & Power
Small 706,414 650,384 635,112 7,905,792
Medium 30,930 30,882 30,011 361,559
Inter Departmental 1,953 1,902 1,656 21,609
Total disc. Sales 2,963,316 2,926,834 3,249,190 37,620,960
</TABLE>
SSM-11
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
WORKPAPERS SUPPORTING
APPENDIX B
ELECTRIC SALES FORECAST
i
<PAGE>
Pacific Gas and Electric Company
Rate Reduction Bond Application
Energy Consumption Forecast Workpapers
TABLE OF CONTENTS
Pages
-----
FORECAST RESULTS
1. SHORT TERM ECONOMETRIC FORECAST
a.) Sales Summary WVM-01 - WVM-02
b.) Economic and Demographic Assumptions WVM-03 - WVM-03
c.) Energy Model Mnemonics WVM-04 - WVM-05
d.) Energy Model Equations WVM-06 - WVM-20
2. LONG TERM END-USE FORECAST
a.) Electricity Consumption Summary WVM-21 - WVM-24
b.) Economic and Demographic Assumptions WVM-25 - WVM-32
c.) Energy Model Methodology and Equations WVM-33 - WVM-48
ii
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
ELECTRIC DEPARTMENT SALES
JANUARY 97 TO DECEMBER 97
(THOUSANDS OF KWH)
<TABLE>
<CAPTION>
ST0197
Jan-97 Feb-97 Mar-97 Apr-7 May-97 Jun-97 Jul-97 Aug-97 Sept-97
-----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
PG&E SALES AND LOADS:
RESIDENTIAL:
INDIVIDUAL: 2,364,785 2,117,464 1,993,714 1,870,912 1,843,750 1,982,893 2190,451 2323,270 2,171,293
MASTER METER 88,627 80,336 74,950 71,238 89,390 73,318 78,757 8,858 79,658
TOTAL 2,453,412 2,197,800 2,068,674 1,942,150 1,913,140 2,056,211 2269,208 2,408,128 2250,952
LIGHT AND POWER:
SMALL 544,572 551,364 557,950 521,244 542,358 581,278 823,474 848,879 848,814
MEDIUM 1,597,073 1,616,990 1,636,307 1,630,130 1,696,164 1,817,882 1,841,216 1,916,241 1,916,048
TOTAL 2,141,645 2,168,354 2,194,257 2,151,374 2,238,522 2,399,160 2,464,690 2,565,121 2,564,862
INTERDEPARTMENTAL 12,022 11,285 14,325 11,192 12,499 14,146 12197 12,710 13,409
<CAPTION>
ST0197
Oct-97 Nov-97 Dec-97 TOTAL
---------------------------------------------
<S> <C> <C> <C> <C>
PG&E SALES AND LOADS:
RESIDENTIAL:
INDIVIDUAL: 1,892511 1,909,230 2,197,482 24,857,756
MASTER METER 71,770 72,963 Sz994 926,870
TOTAL 1,964,281 1,982193 2,280,477 25,784,626
LIGHT AND POWER:
SMALL 616,451 567,650 554,348 6,958,384
MEDIUM 1,832,040 1,687,008 1,647,475 20,834,574
TOTAL 2,448,492 2,254,658 2,201,824 27,792,958
INTERDEPARTMENTAL 14,954 12,251 10,665 151,656
</TABLE>
1
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
ELECTRIC DEPARTMENT SALES
JANUARY 98 TO DECEMBER 98
THOUSANDS OF KWH)
<TABLE>
<CAPTION>
ST0197
Jan-98 Feb-98 Mar-98 Apr-98 May-98 Jun-98 Jul-98 Aug-98 Sept-98
----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
PG&E SALES AND LOADS:
RESIDENTIAL:
INDIVIDUAL: 2,425,895 2172,163 2,045,235 1,924,287 1,895,349 2,039,463 2,266,929 2,404,385 2,247,102
MASTER METER 90,050 81,625 76,163 72,324 70,448 74,435 79,847 64,005 80,761
TOTAL 2,515,945 2,253,809 2,121,398 1,996,611 1,966,798 2,113,898 2346,776 2,488,390 2,327,863
LIGHT AND POWER:
SMALL 563,446 570,473 577,268 542,114 564,075 804,553 654,062 680,714 680,645
MEDIUM 1,611,557 1,631,655 1,651,147 1,652,909 1,719,866 1,843,285 1,871,753 1,948,024 1,947,827
TOTAL 2,175,003 2,202,128 2,228,435 2,195,023 2,283,940 2,447,838 2,525,815 2,628,737 2,628,472
INTERDEPARTMENTAL 12,092 11,351 14,408 11,225 12,535 14,187 12,226 12,740 13,441
<CAPTION>
ST0197
Oct-98 Nov-98 Dec-98 TOTAL
--------------------------------------------
<S> <C> <C> <C> <C>
PG&E SALES AND LOADS:
RESIDENTIAL:
INDIVIDUAL: 1,947,478 1,964,682 2261,307 25,595,297
MASTER METER 72,413 73,617 83,738 939,426
TOTAL 2,019,891 2,038,299 2,345,045 26,534,723
LIGHT AND POWER:
SMALL 848,840 597,475 583,474 7,267,158
MEDIUM 1,863,114 1,715,622 1,675,419 21,132,177
TOTAL 2,511,954 2,313,096 2,258,893 28,399,335
INTERDEPARTMENTAL 14,983 12,274 10,685 152,145
</TABLE>
2
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
ELECTRIC DEPARTMENT
ECONOMIC AND DEMOGRAPHIC ASSUMPTIONS
USED IN PREPARTATION OF JAN-1997 SHORTIERN FORECAST
<TABLE>
<CAPTION>
1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998
---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
CONSUMER PRICE INDEX
CALIFORNIA 1.55 1.64 1.75 1.83 1.86 1.88 1.92 1.96 2.00 2.06 2.11
% CHANGE 5.59 5.94 6.57 4.77 1.96 0.99 1.94 2.20 2.16 2.66 2.75
WHOLESALE PRICE INDEX
ALL COMMODITIES 1.07 1.12 1.16 1.17 1.17 1.19 1.20 1.25 1.27 1.28 1.29
% CHANGE 4.01 4.95 3.60 0.21 0.57 1.47 1.30 3.83 1.90 0.53 0.88
COMMERCIAL EMPLOYMENT
SERVICE AREA(THOUSANDS) 2262.50 2332.25 2430.00 2549.00 2614.75 2702.25 2744.00 2754.25 2772.00 2818.0 2907.50
% CHANGE 4.50 3.08 4.19 4.90 2.58 3.35 1.55 0.37 0.64 1.66 3.18
REAL PERSONAL INCOME PER CAPITA
ELECTRIC SERVICE AREA
(THOUSANDS OF DOLLARS) 17.503 17.648 17.899 17.525 17.913 17.840 17.831 18.514 18.967 19.235 19.589
% CHANGE 1.65 0.83 1.43 -2.09 2.22 -0.41 -0.05 3.83 2.45 1.41 1.84
REAL RESIDENTIAL ELECTRIC PRICE
(DOLLARS/KWH) 0.0722 0.0739 0.0718 0.0733 0.0707 0.0718 0.0703 0.0688 0.0653 0.0636 0.0557
% CHANGE 7.91 2.34 -2.81 2.16 -3.60 1.59 -2.17 -2.15 -5.07 -2.58 -12.41
REAL SMALL LIGHT & POWER
ELECTRIC PRICE (DOLLARS/KWH) 0.0909 0.0919 0.0991 0.1129 0.1192 0.1174 0.1133 0.1077 0.0987 0.1014 0.0904
%CHANGE -2.02 1.10 7.88 13.97 5.51 -1.49 -3.50 -4.95 -8.37 2.76 -10.80
</TABLE>
3
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
ELECTRIC ENERGY MODEL
INDEX
<TABLE>
<CAPTION>
MNEMONIC DESCRIPTION
- -------- -----------
<S> <C>
AIRUSEPC AIR CONDITIONING USAGE PER CAPITA - PG&E AREA
AVGPCNM AVERAGE PRICE OF ELECTRICITY - SMALL LIGHT AND
POWER
CPI@CA CONSUMER PRICE INDEX (URBAN) - ALL ITEMS -
CALIFORNIA
DIABLO84 ENERGY VARIABLE - TESTING DIABLO CANYON
DIABOTEST BINARY VARIABLE - TESTING DIABLO CANYON
ECOM1@PGE COMMERCIAL EMPLOYMENT - SERVICE AREA
ECOM90 COMMERCIAL EMPLOYMENT FROM 1990 TO PRESENT
PECDDBLM80 COOLING DEGREE DAYS - ELECTRIC SERVICE AREA
COMPOSITE BILLING BASIS ON 80 DEGREE BASE
PECRIM CUSTOMERS - RESIDENTIAL INDIVIDUAL METER
PECRMM CUSTOMERS - RESIDENTIAL MASTER METER
PEHDDBLM60 HEATING DEGREE DAYS - ELECTRIC SERVICE AREA
COMPOSITE BILLING BASIS ON 60 DEGREE BASE
PEPRIM MARGINAL PRICE OF ELECTRICITY - RESIDENTIAL
INDIVIDUAL METER
PEPRIML 10 YEAR AVERAGE MARGINAL PRICE OF ELECTRICITY -
RESIDENTIAL INDIVIDUAL METERED
PESCDM SALES - MEDIUM LIGIIT AND POWER
PESCNM SALES - SMALL LIGHT AND POWER
PESIDMNA SALES - INTERDEPARTMENTAL
PESRIM SALES - RESIDENTIAL INDIVIDUAL METER
PESRMM SALES - RESIDENTIAL MASTER METER
PESTPM SALES - PARTIAL TOTAL
MNEMONIC DESCRIPTION
- -------- -----------
</TABLE>
4
<PAGE>
<TABLE>
<S> <C>
RECLASS9193 BINARY VARIABLE - RECLASSIFICATION
SQl BINARY SEASONAL VARIABLE - FIRST QUARTER
SQ2 BINARY SEASONAL VARIABLE - SECOND QUARTER
SQ3 BINARY SEASONAL VARIABLE - THIRD QUARTER BINARY
SEASONAL VARIABLE - FOURTH QUARTER
TREND LINEAR TIME TREND
WPI PRODUCER PRICE INDEX - TOTAL
YPNR87@PGE REAL PER CAPITA PERSONAL INCOME
</TABLE>
5
<PAGE>
equation pesrim'Sale5:Res. Indiv. Meter' log(pesrim/pecrim)=!
(sql+sq4 )*pehddblm60, (sq/2/+sq/3/)*pecddblm80*airusepc, !
log(peprim/cpi@ca), log(pepriml/cpi@ca), trend, !
log(ypnr87@pge);
normalize pesrim = exp(??) * pecrim;
fit;
PESRIM Sales:Res.Indiv.Meter
Ordinary Least Squares
QUARTERLY data for 83 periods from 1976Q1 to 1996Q3
Date: 27 JAN 1997
log ( pesrim/pecrim)
= 0.00020 * (sql+sq4)*pehddblm60
(27.8119)
+ 0.00399 * (sq2+sq3)*pecddblm80*airusepc
(23.5760)
- 0.06418 * log (peprim/cpi@ca) - 0.10146*log(pepriml/cpi@ca)
(4.06109) (3.61758)
-0.00217 * trend + 0.42631 * log(ypnr87@pge) + 2.95983
(1.55137) (4.03191) (1.09674)
Sum Sq 0.0267 Std Err 0.0188 LHS Mean 0.4454
R Sq 0.9213 R Bar Sq 0.9151 F 6, 76 148.296
D.W.(1) 1.9094 D.W.(4) 1.3164
PESRIM=exp(??)*pecrim
show<residuals>;
<TABLE>
<CAPTION>
: Actual Predicted Residual
<S> <C> <C> <C>
1976Q1 : 0.540 0.574 -0.033
1976Q2 : 0.398 0.398 -0.001
1976Q3 : 0.507 0.461 0.046
1976Q4 : 0.447 0.446 0.001
1977Q1 : 0.515 0.538 -0.023
1977Q2 : 0.349 0.367 -0.018
1977Q3 : 0.485 0.453 0.032
1977Q4 : 0.401 0.414 -0.013
1978Q1 : 0.492 0.465 0.027
1978Q2 : 0.375 0.382 -0.008
1978Q3 : 0.491 0.467 0.024
1978Q4 : 0.472 0.473 -0.001
1979Q1 : 0.585 0.575 0.010
1979Q2 : 0.419 0.425 -0.005
1979Q3 : 0.507 0.513 -0.006
1979Q4 : 0.466 0.461 0.005
1980Q1 : 0.529 0.525 0.004
1980Q2 : 0.377 0.372 0.005
1980Q3 : 0.473 0.448 0.025
1980Q4 : 0.427 0.445 -0.017
</TABLE>
6
<PAGE>
<TABLE>
<CAPTION>
Actual Predicted Residual
<S> <C> <C> <C>
1981Q1 : 0.479 0.510 -0.030
1981Q2 : 0.370 0.391 -0.021
1981Q3 : 0.506 0.479 0.026
1981Q4 : 0.422 0.409 0.013
1982Q1 : 0.492 0.507 -0.015
1982Q2 : 0.325 0.341 -0.015
1982Q3 : 0.403 0.406 -0.003
1982Q4 : 0.402 0.424 -0.022
1983Q1 : 0.493 0.490 0.003
1983Q2 : 0.385 0.357 0.008
1983Q3 : 0.441 0.461 -0.019
1983Q4 : 0.413 0.404 0.010
1984Q1 : 0.494 0.489 0.005
1984Q2 : 0.355 0.381 -0.025
1984Q3 : 0.515 0.537 -0.022
1984Q4 : 0.453 0.420 0.032
1985Q1 : 0.528 0.531 -0.004
1985Q2 : 0.382 0.371 0.011
1985Q3 : 0.454 0.476 -0.021
1985Q4 : 0.438 0.443 -0.005
</TABLE>
<TABLE>
<CAPTION>
Actual Predicted Residual
<S> <C> <C> <C>
1986Q1 : 0.475 0.458 0.017
1986Q2 : 0.363 0.364 -0.001
1986Q3 : 0.452 0.476 -0.023
1986Q4 : 0.399 0.409 -0.010
1987Q1 : 0.516 0.504 0.012
1987Q2 : 0.373 0.383 -0.009
1987Q3 : 0.451 0.452 -0.000
1987Q4 : 0.445 0.402 0.043
1988Q1 : 0.508 0.492 0.016
1988Q2 : 0.350 0.353 -0.002
1988Q3 : 0.525 0.531 -0.006
1988Q4 : 0.431 0.405 0.026
1989Q1 : 0.557 0.544 0.014
1989Q2 : 0.349 0.360 -0.011
1989Q3 : 0.447 0.461 -0.014
1989Q4 : 0.419 0.410 0.008
1990Q1 : 0.529 0.529 -0.000
1990Q2 : 0.332 0.353 -0.021
1990Q3 : 0.486 0.504 -0.018
1990Q4 : 0.412 0.422 -0.011
</TABLE>
7
<PAGE>
<TABLE>
<CAPTION>
Actual Predicted Residual
<S> <C> <C> <C>
1991Q1 : 0.494 0.504 -0.009
1991Q2 : 0.343 0.335 0.008
1991Q3 : 0.473 0.472 0.001
1991Q4 : 0.440 0.392 0.048
1992Q1 : 0.473 0.479 -0.006
1992Q2 : 0.370 0.376 -0.005
1992Q3 : 0.489 0.493 -0.005
1992Q4 : 0.401 0.397 0.005
1993Q1 : 0.509 0.501 0.008
1993Q2 : 0.339 0.339 0.000
1993Q3 : 0.503 0.493 0.010
1993Q4 : 0.413 0.399 0.013
1994Q1 : 0.456 0.490 -0.004
1994Q2 : 0.323 0.336 -0.013
1994Q3 : 0.509 0.506 0.003
1994Q4 : 0.443 0.430 0.013
1995Q1 : 0.483 0.493 -0.005
1995Q2 : 0.328 0.364 -0.036
1995Q3 : 0.517 0.512 0.005
1995Q4 : 0.400 0.412 -0.012
</TABLE>
<TABLE>
<CAPTION>
Actual Predicted Residual
<S> <C> <C> <C>
1996Q1 : 0.481 0.505 -0.024
1996Q2 : 0.375 0.376 -0.001
1996Q3 : 0.567 0.523 0.038
</TABLE>
8
<PAGE>
! return;
set per 78:2 96:3;
equation pesrmm 'Sales: Res.Master Meter' pesrmm = sq1, sq2, sq3,! pehddblm60,
pecddblm80*airusepc, !
pecrmm ar=1;
fit;
PESRMM Sales: Res. Master Meter
Cochrane-Orcutt
QUARTERLY data for 74 periods from 1978Q2 to 1996Q3
Date: 27 JAN 1997
pesrmm
= 3454.41 * sql - 7327.87 * sq2 + 7210.58 * sq3
(1.17920) (4.65116) (1.92480)
+ 45.8766 * pehddblm60 + 572.254 * pecddblm80*airusepc
(7.39651) (5.99848)
+ 2.16648 * pecrmm + 147278
(2.43545) (6.35243)
Sum Sq 2E+09 Std Err 4775.23 LHS Mean 227509
R Sq 0.9422 R Bar Sq 0.9360 F 7, 66 153.626
D.W.( 1) 2.0939 D.W.( 4) 1.4192
AR_0 = + 0.75896 * AR_1
( 9.7849)
show<residuals>;
<TABLE>
<CAPTION>
Actual Predicted Residual
<S> <C> <C> <C>
1978Q2 : 173017.000 170205.517 2811.483
1978Q3 : 191896.000 195887.876 -3991.876
1978Q4 : 194652.000 198922.526 -4270.526
1979Q1 : 220630.000 220138.997 491.003
1979Q2 : 192415.000 186178.272 6236.728
1979Q3 : 209435.000 210662.489 -1227.489
1979Q4 : 202280.000 204020.776 -1740.776
1980Q1 : 216239.000 219525.662 -3286.662
1980Q2 : 191495.000 190547.107 947.893
1980Q3 : 214668.000 208822.113 5845.887
1980Q4 : 210565.000 215008.578 -4443.578
1981Q1 : 218455.000 226383.233 -7928.233
1981Q2 : 202842.000 194204.022 8637.978
1981Q3 : 231064.000 222227.496 8836.504
1981Q4 : 215636.000 218518.220 -2882.220
1982Q1 : 233897.000 245355.878 -11458.878
1982Q2 : 206019.000 204891.891 1127.109
1982Q3 : 220437.000 216263.120 4173.880
1982Q4 : 220983.000 222925.439 1942.439
1983Q1 : 242151.000 239024.477 3126.523
</TABLE>
9
<PAGE>
<TABLE>
<CAPTION>
Actual Predicted Residual
<S> <C> <C> <C>
1983Q2 : 212589.000 213019.979 -430.979
1983Q3 : 228399.000 229161.311 -762.311
1983Q4 : 220231.000 219433.969 797.031
1984Q1 : 243461.000 240396.076 3064.924
1984Q2 : 209272.000 215878.524 -6606.524
1984Q3 : 249414.000 237022.526 12391.474
1984Q4 : 238061.000 233676.533 4384.467
1985Q1 : 263594.000 261494.508 2099.492
1985Q2 : 228130.000 224002.129 4127.871
1985Q3 : 240155.000 244240.880 -4085.880
1985Q4 : 233929.000 235961.434 2967.566
1986Q1 : 249671.000 243226.204 8444.796
1986Q2 : 223410.000 221413.024 1996.976
1986Q3 : 239216.000 244009.180 -4793.180
1986Q4 : 229775.000 227106.245 2668.755
1987Q1 : 259088.000 253232.257 5855.743
1987Q2 : 222453.000 223742.343 -1289.343
1987Q3 : 234972.000 237810.790 -2838.790
1987Q4 : 233975.000 228307.170 5667.830
1988Q1 : 254773.000 252804.093 1968.907
Actual Predicted Residual
1988Q2 : 216864.000 219513.478 -2649.478
1988Q3 : 247610.000 247126.596 483.404
1988Q4 : 233153.000 230108.095 3044.905
1989Q1 : 269554.000 264529.351 5024.649
1989Q2 : 219946.000 222599.833 -2653.833
1989Q3 : 233906.000 240196.545 -6290.545
1989Q4 : 233083.000 226383.000 6700.000
1990Q1 : 263906.000 260692.908 3213.092
1990Q2 : 217309.000 218981.462 -1672.462
1990Q3 : 244329.000 243640.386 688.614
1990Q4 : 234826.000 234589.476 236.524
1991Q1 : 258294.000 256018.012 2275.988
1991Q2 : 223384.000 225621.006 -2237.006
1991Q3 : 240231.000 241166.100 -935.100
1991Q4 : 237233.000 233755.409 3477.591
1992Q1 : 246759.000 249840.268 -3081.268
1992Q2 : 220286.000 214142.806 6143.194
1992Q3 : 239857.000 245008.009 -5151.009
1992Q4 : 224218.000 228969.131 -4751.131
1993Q1 : 251835.000 249220.984 2614.016
</TABLE>
10
<PAGE>
<TABLE>
<CAPTION>
Actual Predicted Residual
<S> <C> <C> <C>
1993Q2 : 210988.000 211734.747 -746.747
1993Q3 : 239949.000 240283.747 -334.747
1993Q4 : 225201.000 229600.642 -4399.642
1994Q1 : 242150.000 247171.637 -5021.637
1994Q2 : 203383.000 208450.677 -5067.677
1994Q3 : 231443.000 235630.453 -4187.453
1994Q4 : 228626.000 225618.578 3007.422
1995Q1 : 238581.000 244272.834 -5691.834
1995Q2 : 202766.000 209201.466 -6435.466
1995Q3 : 234430.000 230916.877 3513.123
1995Q4 : 214851.000 223372.780 -8521.780
1996Q1 : 238242.000 237952.621 289.379
1996Q2 : 206823.000 209062.717 -2239.717
1996Q3 : 233329.000 234663.506 -1334.506
</TABLE>
11
<PAGE>
set per 76:1 96:3;
equation pescnm 'Sales: Small L&P' log(pescnm)= log(pescnm.1), sql, s
sq3,(sq2+sq3 ) *pecddblm50*airusepc, !
log(ecoml@pge) log(avgpcnm/wpi) ,log(ecom90);
normalize pescnm = exp(??);
fit;
PESCNM Sales: Small L&P
Ordinary Least Squares
QUARTERLY data for 83 periods from 1976Q1 to 1996Q3
Date: 27 JAN 1997
log(pescnm)
- - 0.91858 * lo g(pescnm) [-1] + 0.07104 * sql + 0.05275 * sq2
(31.2673) (8.11351) (5.12094)
+ 0.10217 * sq3 + 0.00253 * (sq2+sq3 ) *pecddblm80*airusepc
(3.99811) (4.31751)
+ 0.08666 * log(ecoml@pge) - 0.03822* log(avgpcnm/wpi)
(2.66966) (1.07516)
Sum Sq 0.0531 St d Err 0.0268 LHS Mean 14.1953
R Sq 0.9842 R Bar Sq 0.9825 F 8, 74 577.209
D.W.(1) 2.0604 D.W.(4) 1.9161
H -0.3013
PESCNM=exp(??)
12
<PAGE>
show<residuals>;
<TABLE>
<CAPTION>
Actual Predicted Residual
<S> <C> <C> <C>
1976Q1 : 13.929 13.922 0.007
1976Q2 : 13.879 13.913 -0.035
1976Q3 : 13.971 13.967 0.004
1976Q4 : 13.889 13.882 0.008
1977Q1 : 13.864 13.876 -0.011
1977Q2 : 13.808 13.846 -0.038
1977Q3 : 13.935 13.906 0.029
1977Q4 : 13.847 13.845 0.002
1978Q1 : 13.842 13.837 0.005
1978Q2 : 13.850 13.836 0.014
1978Q3 : 13.963 13.952 0.012
1978Q4 : 13.918 13.888 0.030
1979Q1 : 13.950 13.923 0.027
1979Q2 : 13.935 13.962 -0.026
1979Q3 : 14.045 14.060 -0.015
1979Q4 : 13.989 13.976 0.014
1980Q1 : 13.973 13.995 -0.022
1980Q2 : 13.942 13.962 -0.020
1980Q3 : 14.065 14.041 0.024
1980Q4 : 13.985 13.992 -0.007
Actual Predicted Residual
1981Q1 : 13.942 13.993 -0.051
1951Q2 : 13.969 13.960 0.009
1981Q3 : 14.103 14.102 0.001
1981Q4 : 13.963 14.028 -0.065
1982Q1 : 13.961 13.966 -0.005
1952Q2 : 13.945 13.960 -0.011
1952Q3 : 14.068 14.047 0.021
1982Q4 : 14.011 14.002 0.009
1983Q1 : 14.035 14.024 0.012
1983Q2 : 14.035 14.048 -0.013
1983Q3 : 14.175 14.174 0.002
1983Q4 : 14.099 14.108 -0.009
1984Q1 : 14.122 14.109 0.013
1984Q2 : 14.165 14.139 0.026
1984Q3 : 14.353 14.337 0.017
1984Q4 : 14.303 14.266 0.036
1985Q1 : 14.325 14.288 0.036
1985Q2 : 14.373 14.317 0.056
1985Q3 : 14.536 14.436 0.050
1955Q4 : 14.422 14.431 -0.010
</TABLE>
13
<PAGE>
<TABLE>
<CAPTION>
Actual Predicted Residual
<S> <C> <C> <C>
1986Q1 : 14.372 14.396 -0.024
1986Q2 : 14.375 14.357 0.019
1956Q3 : 14.423 14.490 -0.066
1986Q4 : 14.303 14.332 -0.029
1987Q1 : 14.320 14.297 0.024
1987Q2 : 14.351 14.332 0.019
1987Q3 : 14.449 14.456 -0.006
1987Q4 : 14.375 14.361 0.014
1988Q1 : 14.349 14.369 -0.020
1988Q2 : 14.347 14.342 0.005
1988Q3 : 14.494 14.515 -0.021
1988Q4 : 14.400 14.406 -0.005
1989Q1 : 14.401 14.395 0.006
1989Q2 : 14.385 14.400 -0.015
1989Q3 : 14.478 14.504 -0.026
1989Q4 : 14.396 14.393 0.003
1990Q1 : 14.412 14.363 0.049
1990Q2 : 14.379 14.374 0.005
1990Q3 : 14.488 14.497 -0.009
1990Q4 : 14.381 14.376 0.005
Actual Predicted Residual
1991Q1 : 14.347 14.350 -0.003
1991Q2 : 14.318 14.311 0.007
1991Q3 : 14.411 14.429 -0.018
1991Q4 : 14.355 14.303 0.052
1992Q1 : 14.287 14.325 -0.038
1992Q2 : 14.322 14.278 0.044
1992Q3 : 14.391 14.440 -0.049
1992Q4 : 14.248 14.285 -0.038
1993Q1 : 14.235 14.230 0.004
1993Q2 : 14.196 14.214 -0.017
1993Q3 : 14.335 14.335 0.001
1993Q4 : 14.230 14.238 -0.008
1994Q1 : 14.219 14.219 0.001
1994Q2 : 14.180 14.205 -0.025
1994Q3 : 14.361 14.333 0.028
1994Q4 : 14.250 14.263 -0.014
1995Q1 : 14.243 14.239 0.004
1995Q2 : 14.207 14.238 -0.031
1995Q3 : 14.385 14.353 0.035
1995Q4 : 14.301 14.290 0.011
Actual Predicted Residual
1996Q1 : 14 277 14.290 -0.013
1996Q2 : 14.302 14.274 0.028
1996Q3 : 14.438 14.449 -0.011
</TABLE>
14
<PAGE>
<TABLE>
<CAPTION>
Actual Predicted Residual
<S> <C> <C> <C>
1990Q2 : 47115.000 35496.943 11621.057
1990Q3 : 43171.000 40873.667 2297.333
1990Q4 : 38791.000 39230.374 -439.374
1991Q1 : 31411.000 37947.797 -6536.797
1991Q2 : 40387.000 35710.684 4676.316
1991Q3 : 42348.000 38810.596 3537.404
1991Q4 : 37836.000 39015.981 -1179.981
1992Q1 : 30592.000 37771.837 -7179.837
1992Q2 : 42277.000 35643.572 6633.428
1992Q3 : 43091.000 39545.207 3545.793
1992Q4 : 32846.000 39217.595 -6371.595
1993Q1 : 32385.000 36215.309 -3830.309
1993Q2 : 34494.000 36169.857 -1675.857
1993Q3 : 52525.000 37188.714 15336.286
1993Q4 : 34624.000 42065.302 -7441.302
1994Q1 : 28567.000 36783.029 -8216.029
1994Q2 : 34190.000 35055.705 -865.705
1994Q3 : 39365.000 37167.619 2197.381
1994Q4 : 32765.000 38087.559 -5319.589
1995Q1 : 30721.000 36199.027 -5478.027
Actual Predicted Residual
1995Q2 : 32699.000 35681.530 -2982.530
1995Q3 : 41771.000 36658.794 5082.206
1995Q4 : 29624.000 38.810.816 -9186.816
1996Q1 : 29821.000 35310.536 -5489.536
1996Q2 : 36516.000 35457.036 1058.964
1996Q3 : 36456.000 37374.005 -1418.005
</TABLE>
20
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
ELECTRICITY CONSUMPTION BY SECTOR
(GWH)
<TABLE>
<CAPTION>
YEAR RESIDENTIAL COMMERCIAL INDUSTRIAL TCU*
<S> <C> <C> <C> <C>
1980 19,653 13,839 15,892 2,448
1981 19,766 14,578 15,780 2,689
1982 19,295 14,863 15,470 2,614
1983 19,977 15,555 16,250 2,681
1984 20,943 16,520 17,052 2,921
1985 21,293 17,176 17,692 3,091
1986 21,178 17,760 17,457 3,134
1987 22,182 18,984 18,445 3,461
1988 22,826 20,213 19,142 3,514
1989 23,119 21,147 19,598 3,608
1990 23,508 22,183 20,068 3,730
1991 23,838 22,604 19,467 3,772
1992 23,960 23,366 19,414 3,774
1993 24,322 23,773 19,781 3,843
1994 24,517 23,769 19,477 3,743
1995 24,593 24,641 20,668 3,894
1996 25,286 25,821 21,455 4,181
1997 25,531 26,117 21,935 4,316
1998 25,883 26,425 22,457 4,412
1999 26,202 26,699 23,168 4,442
2000 26,553 26,956 23,821 4,500
2001 26,890 27,149 24,379 4,519
2002 27,293 27,701 25,241 4,555
Average Annual Growth Rates (%)
1980-1989 1.8% 4.8% 2.4% 4.4%
1990-1995 0.9% 2.1% 0.6% 0.9%
1996-2002 1.3% 1.2% 2.7% 1.4%
</TABLE>
21
<PAGE>
* Excludes BART.
PACIFIC GAS AND ELECTRIC COMPANY
ELECTRICITY CONSUMPTION BY SECTOR
(GWH)
<TABLE>
<CAPTION>
RESIDENTIAL COMMERCIAL
Restau- Retail & Miscella-
YEAR TOTAL Offices rants Food Health neous TOTAL
<S> <C> <C> <C> <C> <C> <C> <C>
1980 19,653 2,911 1,237 4,041 1,030 4,619 13,838
1981 19,766 3,238 1,307 4,218 1,040 4,773 14,576
1982 19,295 3,533 1,310 4,036 1,042 4,941 14,862
1983 19,977 3,774 1,392 4,103 1,061 5,226 15,556
1984 20,943 4,043 1,485 4,324 1,107 5,560 16,519
1985 21,293 4,225 1,550 4,413 1,129 5,859 17,176
1986 21,178 4,513 1,602 4,548 1,169 5,929 17,761
1987 22,182 4,916 1,712 4,756 1,234 6,366 18,984
1988 22,826 5,321 1,773 5,042 1,305 6,772 20,213
1989 23,119 5,910 1,803 5,205 1,182 7,049 21,149
1990 23,508 6,151 1,870 5,367 1,246 7,550 22,184
1991 23,838 6,311 1,860 5,415 1,264 7,753 22,604
1992 23,960 6,535 1,914 5,579 1,336 8,003 23,366
1993 24,322 6,535 1,940 5,645 1,432 8,221 23,773
1994 24,517 6,392 1,943 5,635 1,436 8,363 23,769
1995 24,593 6,626 2,003 5,713 1,526 8,773 24,641
1996 25,286 7,028 2,123 5,733 1,673 9,264 25,821
1997 25,531 7,136 2,159 5,733 1,703 9,385 26,117
1998 25,883 7,241 2,197 5,746 1,735 9,506 26,425
1999 26,202 7,329 2,228 5,759 1,768 9,616 26,699
2000 26,553 7,402 2,259 5,776 1,797 9,723 26,956
2001 26,890 7,459 2,271 5,793 1,818 9,809 27,149
2002 27,293 7,623 2,315 5,882 1,863 0,018 27,701
Average Annual Growth Rates (%)
1980-1989 1.8% 8.2% 4.3% 2.9% 1.5% 4.8% 4.8%
1990-1995 0.9% 1.5% 1.4% 1.3% 4.1% 3.0% 2.1%
1996-2002 1.3% 1.4% 1.5% 0.4% 1.8% 1.3% 1.2%
</TABLE>
22
<PAGE>
PACIFIC GAS and ELECTRIC COMPANY
ELECTRICITY CONSUMPTION by SECTOR
(GWH)
<TABLE>
<CAPTION>
INDUSTRIAL
YEAR SIC 10-19 SIC 20 SIC 22 SIC 23 SIC 24 SIC 25 SIC 26 SIC 27 SIC 28 SIC 29 SIC 30 SIC 31 SIC 32
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1980 1,897 2,015 41 29 866 30 701 217 1,218 3,523 335 20 1,184
1981 2,387 1,955 34 29 750 31 630 222 1,174 3,156 312 20 1,193
1982 2,874 1,959 27 30 687 30 613 225 1,012 2,884 327 19 1,041
1983 3,098 1,949 29 34 798 29 762 240 994 3,036 365 16 996
1984 3,388 1,996 29 36 809 30 794 279 837 3,032 388 12 1,124
1985 3,695 1,992 29 34 850 30 770 279 927 3,187 391 9 1,142
1986 3,158 1,989 29 37 1,061 30 718 285 929 3,190 384 8 1,253
1987 3,550 2,084 27 39 1,16i 33 793 302 963 3,321 413 12 1,24g
1988 3,716 2,108 30 40 1,228 35 802 320 1,024 3,328 444 21 1,277
1989 3,802 2,238 32 44 1,268 36 745 337 1,028 3,092 478 25 1,282
1990 3,778 2,291 49 38 1,284 32 804 335 1,073 3,288 511 22 1,280
1991 3,232 2,461 49 37 1,136 32 822 344 1,095 3,473 519 18 1,181
1992 3,281 2,478 53 39 1,083 29 816 355 1,123 3,452 540 18 1,192
1993 3,236 2,523 55 41 1,118 32 855 358 1,104 3,647 556 18 1,218
1994 3,095 2,577 56 41 1,111 30 820 363 972 3,645 551 21 1,168
1995 2,954 2,867 56 40 1,151 31 905 379 996 3,926 556 18 1,306
1996 3,258 2,922 57 40 1,206 31 894 357 1,020 3,861 555 17 1,261
1997 3,231 2,972 60 42 1,206 31 934 354 1,052 3,925 569 16 1,252
1998 3,206 3,009 61 42 1,234 31 946 353 1,084 3,984 591 15 1,260
1999 3,197 3,039 61 42 1,256 31 962 353 1,110 4,039 620 14 1,277
2000 3,187 3,063 62 42 1,273 30 972 354 1,131 4,078 641 14 1,299
2001 3,178 3,088 62 41 1,282 30 979 355 1,146 4,096 655 14 1,306
2002 3,184 3,147 63 42 1,306 31 995 358 1,173 4,156 677 14 1,324
Average Annual Growth Rates (%)
1980-1989 8.0% 1.2% -2.7% 4.7% 4.3% 2.0% 0.7% 5.0% -1.9% -1.4% 4.0% 2.5% 0.9%
1990-1995 4.8% 4.6% 2.6% 0.8% -2.2% -0.6% 2.4% 2.5% -1.5% 3.6% 1.7% -3.9% 0.4%
1996-2002 0.4% 1.2% 1.6% 0.8% 1.3% 0.1% 1.8% 0.1% 2.4% 1.2% 3.4% -3.2% 0.8%
<CAPTION>
YEAR SIC 33 SIC 34 SIC 35 SIC 36 SIC 37 SIC 38 SIC 39 TOTAL
<S> <C> <C> <C> <C> <C> <C> <C> <C>
1980 759 333 802 1,083 519 277 40 15,889
1981 713 323 881 1,103 536 287 45 15,781
1982 535 344 898 1,139 481 293 53 15,471
1983 534 369 955 1,234 450 303 57 56,248
1984 595 413 1,076 1,333 505 336 42 17,054
1985 649 422 1,097 1,366 442 351 29 17,691
1986 521 412 1,108 1,374 563 381 27 17,457
1987 493 397 1,158 1,433 554 433 32 18,445
1988 575 391 1,267 1,477 560 465 33 19,141
1989 671 399 1,625 1,380 634 448 33 19,591
1990 650 388 1,645 1,462 627 480 34 20,071
1991 578 381 1,585 1,445 612 446 41 19,467
1992 557 375 1,521 1,397 630 432 40 19,414
1993 717 400 1,444 1,353 613 446 46 19,781
1994 746 416 1,377 1,425 563 456 44 19,477
1995 765 446 1,500 1,592 650 476 53 20,668
1996 788 463 1,774 1,784 628 493 55 21,465
1997 807 472 1,912 1,937 604 502 56 21,935
1998 837 485 2,062 2,099 597 503 56 22,457
1999 872 498 2,282 2,332 617 508 58 23,168
2000 894 508 2,518 2,545 640 511 59 23,821
2001 897 514 2,748 2,750 657 519 61 24,379
2002 907 525 3,041 3,023 681 530 63 25,241
Average Annual Growth Rates (%)
1980-1989 -1.4% 2.0% 8.2% 2.7% 22% 5.5% -2.1% 2.4%
1990-1995 3.3% 2.8% -1.8% 1.7% 07% -0.2% 9.5% 0.6%
1996-2002 2.4% 2.1% 9.4% 9.2% 14% 1.2% 2.1% 2.7%
</TABLE>
23
<PAGE>
PACIFIC GAS and ELECTRIC COMPANY
ELECTRICITY CONSUMPTION by SECTOR
(GWH)
<TABLE>
<CAPTION>
TCU
SIC
44/45/47/
YEAR SIC 40 SIC 41 SIC 42 SIC 43 7520-25 SIC 46 SIC 48 SIC 49 SIC 97 TOTAL
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1980 53 26 61 98 202 157 515 975 361 2,448
1981 52 26 67 95 203 187 574 1,117 368 2,689
1982 51 27 64 98 205 174 577 1,049 369 2,614
1983 49 28 63 97 219 159 578 1,108 380 2,681
1984 50 30 68 94 227 185 609 1,247 411 2,921
1985 46 34 73 77 236 196 645 1,345 439 3,091
1986 43 36 70 73 201 234 634 1,423 420 3,134
1987 42 39 80 85 215 248 639 1,617 496 3,461
1988 41 43 80 72 208 330 632 1,821 487 3,514
1989 40 45 57 81 230 443 630 1,586 496 3,608
1990 41 46 57 83 243 439 657 1,651 513 3,730
1991 41 50 56 83 245 495 681 1,617 504 3,772
1992 42 49 56 79 232 482 702 1,655 477 3,774
1993 39 37 56 77 239 479 734 i,722 459 3,843
1994 38 42 57 76 236 482 706 1,749 357 3,743
1995 43 51 57 82 242 586 742 1,761 330 3,894
1996 43 54 59 200 239 661 739 1,866 320 4,181
1997 42 150 57 209 237 695 736 1,880 310 4,316
1998 42 200 56 217 237 729 733 1,894 304 4,412
1999 42 179 56 226 236 764 732 1,906 301 4,442
2000 42 187 56 236 236 799 730 1,917 297 4,500
2001 42 155 56 246 236 834 729 1,927 294 4,519
2002 42 140 56 256 236 869 728 1,936 292 4,555
Average Annual Growth Rates (%)
1980-1989 -3,1% 6,4% -0,8% -2,1% 1,5% 12,2% 2,3% 5,6% 3,6% 4,4%
1990-1995 1,0% 1,8% 0,0% -0,3% -0,1% 6,0% 2,5% 1,3% -8,4% 0,9%
1996-2002 -0,4% 17,2% -0,9% 4,2% -0,2% 4,7% -0,2% 0,6% -1,5% 1,4%
</TABLE>
* Excludes BART,
24
<PAGE>
ECONOMIC & DEMOGRAPHIC ASSUMPTIONS *
PG&E Electric Service and
Climate Area
<TABLE>
<CAPTION>
GROSS
DOMESTIC
PRODUCT PERSONA L
(Chain INCOME POPULATION POPULATION POPULATION
Weighed) (Total) (Coastal) (Inland) (Total)
YEAR PCWGDP (Billions) (Thousands) (Thousands) (Thousands)
<S> <C> <C> <C> <C> <C>
1980 0.604 108.4 4531.2 4520.7 9052.0
1981 0.661 120.9 4613.0 4636.0 9249.0
1982 0.702 129.4 4685.1 4749.4 9434.5
1983 0.732 140.0 4763.9 4862.5 9626.4
1984 0.759 155.4 4838.2 4970.6 9808.8
1985 0.786 168.0 4924.5 5088.4 10012.9
1986 0.806 179.1 5011.1 5196.0 10207.1
1987 0.831 190.1 5090.5 5329.4 10420.0
1988 0.861 204.7 5178.0 5478.4 10656.4
1989 0.897 220.7 5277.9 5642.0 10919.8
1990 0.936 238.9 5353.9 5811.1 11165.0
1991 0.973 247.2 5415.5 5951.1 11366.6
1992 1.000 264.2 5478.5 6056.9 11535.4
1993 1.026 272.2 5516.5 6136.6 11653.1
1994 1.049 279.6 5530.5 6198.9 11729.4
1995 1.076 297.4 5559.9 6257.2 11817.1
1996 1.099 312.6 5595.2 6326.1 11921.2
1997 1.125 326.4 5640.8 6390.3 12031.2
1998 1.150 342.4 5688.2 6462.1 12150.3
1999 1.178 360.4 5733.7 6536.4 12270.1
2000 1.209 379.8 5776.5 6608.3 12384.8
2001 1.242 400.0 5817.5 6678.0 12495.5
2002 1.278 420.5 5856.5 6747.4 12603.9
Average Annual Growth Rates (%)
1980-1989 4.5% 8.2% 1.7% 2.5% 2.1%
1990-1995 2.8% 4.5% 0.8% 1.5% 1.1%
1996-2002 2.6% 5.1% 0.8% 1.1% 0.9%
</TABLE>
* Variables used in the end-use forecast models,
"Regional ACCESS Handbook," DRI/McGraw-HiIl, Inc.,, 1995.
25
<PAGE>
PACIFIC GAS and ELECTRIC COMPANY
ECONOMIC & DEMOGRAPHIC ASSUMPTIONS *
PG&E Electric Service and
Climate Area
<TABLE>
<CAPTION>
EMPLOYMENT EMPLOYMENT EMPLOYMENT
Finance, Finance, Finance,
Insurance, Insurance, Insurance, EMPLOYMENT EMPLOYMENT EMPLOYMENT
Real Real Real EMPLOYMENT EMPLOYMENT EMPLOYMENT Retail Retail Retail
Estate Estate Estate Services Services Services Trade Trade Trade
(Coastal) (Inland) (Total) (Coastal) (Inland) (Total) (Coastal) (Inland) (Total)
YEAR (Thousands) (Thousands) (Thousands) (Thousands) (Thousands) (Thousands) (Thousands) (Thousands) (Thousands)
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1980 170.0 84.2 254.2 483.0 349.7 832.8 488.0 397.9 885.9
1981 173.8 87.8 261.6 501.1 363.7 864.8 493.8 403.8 897.7
1982 175.6 88.3 263.9 501.8 370.1 872.0 489.9 399.1 889.0
1983 177.8 89.9 267.7 510.1 388.0 898.1 504.8 415.4 920.2
1984 180.9 93.5 274.4 547.2 415.8 963.0 535.5 438.0 973.5
1985 183.9 96.5 280.4 578.8 437.5 1016.3 559.2 455.1 1014.3
1986 187.4 100.9 288.2 600.6 454.5 1055.1 570.0 467.9 1037.9
1987 190.8 104.2 294.9 628.4 482.7 1111.1 582.6 490.4 1073.1
1988 194.5 106.5 301.0 659.5 509.9 1169.4 609.3 522.4 1131.8
1989 196.4 110.8 307.2 687.2 526.4 1213.6 618.0 531.6 1149.6
1990 198.0 115.9 313.9 723.4 551.5 1274.9 622.3 544.6 1166.9
1991 200.1 118.2 318.3 742.7 575.9 1318.6 613.9 549.5 1163.4
1992 202.1 119.3 321.4 747.8 601.7 1349.5 596.5 536.9 1133.3
1993 203.7 122.2 325.9 752.5 612.8 1365.3 592.6 536.4 1129.0
1994 201.1 120.0 321.1 774.3 638.9 1413.2 601.0 547.1 1148.0
1995 193.4 117.1 310.5 807.7 680.4 1488.1 618.9 566.3 1185.1
1996 191.2 117.9 309.1 844.8 716.0 1560.7 634.4 583.7 1218.1
1997 191.3 118.6 309.9 871.9 741.3 1613.1 642.9 592.7 1235.5
1998 192.7 120.0 312.7 897.8 766.5 1664.3 653.1 603.8 1256.9
1999 194.6 122.0 316.6 924.3 792.4 1716.6 663.3 615.3 1278.6
2000 197.0 124.2 321.2 947.9 815.6 1763.4 671.5 624.9 1296.4
2001 198.9 125.9 324.8 968.5 835.8 1804.4 680.5 634.7 1315.3
2002 200.8 127.7 328.5 986.8 854.0 1840.9 689.2 644.4 1333.6
Average Annual Growth Rates(%)
1980-1989 1.6% 3.1% 2.1% 4.0% 4.6% 4.3% 2.7% 3.3% 2.9%
1990-1995 -0.5% 0.2% -0.2% 2.2% 4.3% 3.1% -0.1% 0.8% 0.3%
1996-2002 0.8% 1.3% 1.0% 2.6% 3.0% 2.8% 1.4% 1.7% 1.5%
</TABLE>
* Variables used in the end-use forecast models.
"Regional ACCESS Handbook." DRI/McGraw-HilI. Inc., 1995.
26
<PAGE>
PACIFIC GAS and ELECTRIC COMPANY
ECONOMIC & DEMOGRAPHIC ASSUMPTIONS *
Statewide Industrial Production Indices
<TABLE>
<CAPTION>
YEAR IP@CA2O IP@CA22 IP@CA23 IP@CA24 IP@CA25 IP@CA26 IP@CA27 IP@CA28 IP@CA29
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1980 0.868 0.788 0.674 0.785 0.761 0.829 0.692 0.875 0.809
1981 0.902 0.734 0.707 0.737 0.775 0.840 0.716 0.927 0.802
1982 0.913 0.706 0.711 0.585 0.709 0.819 0.739 0.852 0.807
1983 0.896 0.789 0.741 0.704 0.769 0.871 0.771 0.886 0.847
1984 0.916 0.807 0.766 0.754 0.873 0.899 0.815 0.872 0.874
1985 0.936 0.814 0.779 0.784 0.863 0.910 0.837 0.875 0.897
1986 0.972 0.918 0.889 0.922 0.911 0.965 0.894 0.951 0.993
1987 1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000
1988 1.076 1.095 0.988 1.022 0.963 1.082 1.030 1.089 1.027
1989 1.115 1.097 1.009 1.046 0.961 1.132 1.035 1.106 1.039
1990 1.153 1.042 1.059 1.011 0.906 1.127 1.045 1.122 1.003
1991 1.157 0.977 1.105 0.843 0.800 1.127 1.009 1.126 0.975
1992 1.186 1.095 1.163 0.787 0.806 1.167 1.025 1.187 0.895
1993 1.196 1.214 1.170 0.762 0.812 1.211 1.001 1.190 0.836
1994 1.221 1.384 1.294 0.803 0.843 1.250 0.983 1.233 0.813
1995 1.222 1.405 1.363 0.809 0.865 1.249 0.964 1.287 0.803
1996 1.256 1.461 1.388 0.853 0.868 1.242 0.921 1.329 0.794
1997 1.288 1.563 1.485 0.859 0.903 1.308 0.922 1.383 0.813
1998 1.315 1.605 1.521 0.886 0.913 1.333 0.930 1.439 0.830
1999 1.338 1.646 1.545 0.908 0.922 1.365 0.942 1.487 0.847
2000 1.358 1.678 1.561 0.926 0.925 1.387 0.954 1.527 0.861
2001 1.378 1.709 1.581 0.938 0.939 1.405 0.966 1.560 0.869
2002 1.399 1.741 1.599 0.957 0.960 1.430 0.980 1.600 0.882
Average Annual Growth Rates (%)
1980-1989 2.8% 3.7% 4.6% 3.2% 2.6% 3.5% 4.6% 2.6% 2.8%
1990-1995 1.2% 6.2% 5.2% -4.4% -0.9% 2.1% -1.6% 2.8% -4.4%
1996-2002 1.8% 3.0% 2.4% 1.9% 1.7% 2.4% 1.0% 3.1% 1.8%
</TABLE>
* Variables used In the end-use forecast models.
"Regional ACCESS Handbook." DR/IMcGraw-HIII. Inc., 1995.
27
<PAGE>
PACIFIC GAS and ELECTRIC COMPANY
ECONOMIC & DEMOGRAPHIC ASSUMPTIONS *
Statewide Industrial Production Indices
<TABLE>
<CAPTION>
YEAR IP@CA3O IP@CA31 IP@CA32 IP@CA33 IP@CA34 IP@CA35 IP@CA36 IP@CA37 IP@CA38 IP@CA39
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1980 0.739 1.614 0.873 1.088 0.951 0.625 0.665 0.858 0.703 0.939
1981 0.720 1.686 0.871 1.085 0.929 0.658 0.701 0.778 0.725 1.042
1982 0.720 1.500 0.785 0.796 0.872 0.946 0.639 0.796 0.731 1.093
1983 0.756 1.422 0.814 0.868 0.915 0.774 0.788 0.719 0.750 1.013
1984 0.805 1.203 0.870 0.935 0.963 0.926 0.809 0.839 0.869 0.965
1985 0.857 1.027 0.880 0.945 0.957 0.979 0.893 0.930 0.939 0.883
1986 0.944 0.964 0.957 0.916 0.933 1.009 0.951 1.017 0.943 0.916
1987 1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000 1.000
1988 1.196 0.908 1.044 1.026 1.048 1.646 0.897 0.960 1.524 1.050
1989 1.224 0.928 1.090 1.012 1.031 1.752 0.934 1.030 1.483 1.066
1990 1.264 0.895 1.085 0.961 0.991 1.795 0.957 1.054 1.516 1.067
1991 1.231 0.854 0.956 0.880 0.912 1.825 1.009 0.954 1.537 1.049
1992 1.256 0.817 0.935 0.810 0.934 2.002 1.076 0.875 1.517 1.072
1993 1.286 0.833 0.911 0.834 0.924 2.204 1.139 0.778 1.453 1.112
1994 1.396 0.926 0.916 0.910 0.977 2.474 1.307 0.713 1.451 1.270
1995 1.439 0.902 0.919 0.930 0.992 2.937 1.517 0.663 1.471 1.395
1996 1.449 0.865 0.894 0.985 1.038 3.522 1.725 0.649 1.542 1.459
1997 1.502 0.837 0.895 0.997 1.068 3.852 1.900 0.635 1.591 1.489
1998 1.572 0.795 0.906 1.040 1.107 4.213 2.085 0.637 1.613 1.510
1999 1.664 0.751 0.926 1.093 1.145 4.729 2.350 0.667 1.648 1.563
2000 1.738 0.744 0.949 1.129 1.179 5.291 2.603 0.701 1.679 1.613
2001 1.790 0.747 0.961 1.141 1.199 5.849 2.850 0.730 1.721 1.668
2002 1.852 0.751 0.975 1.153 1.227 6.524 3.157 0.762 1.770 1.734
Average Annual Growth Rates (%)
1980-1989 5.8% -6.0% 2.5% -0.8% 0.9% 12.1% 3.8% 2.1% 8.6% 1.4%
1990-1995 2.6% 0.1% -3.3% -0.6% 0.0% 10.4% 9.7% -8.9% -0.6% 5.5%
1996-2002 4.2% -2.3% 1.5% 3.0% 2.8% 10.8% 10.6% 2.7% 2.3% 2.9%
</TABLE>
* Variables used In the end-use forecast models.
"Regional ACCESS Handbook." DRI/McGraw-HiII. Inc., 1995.
28
<PAGE>
PACIFIC GAS and ELECTRIC COMPANY
ECONOMIC & DEMOGRAPHIC ASSUMPTIONS *
PG&E Electric Service and
Climate Area
<TABLE>
<CAPTION>
HOUSEHOLDS HOUSEHOLDS HOUSEHOLDS HOUSEHOLDS HOUSEHOLDS HOUSEHOLDS
(Climate 1) (Climate 2) (Climate 3) (Climate 4) (Climate 5) (Total 1-5)
YEAR (Thousands) (Thousands) (Thousands) (Thousands) (Thousands) (Thousands)
<S> <C> <C> <C> <C> <C> <C>
1980 85.6 152.0 635.0 1076.6 1108.4 3057.6
1981 88.7 157.0 656.8 1107.9 1131.2 3141.6
1982 89.7 159.6 666.2 1117.5 1132.9 3166.0
1983 90.7 161.8 675.7 1128.9 1137.3 3194.4
1984 92.5 166.0 692.4 1150.8 1152.1 3253.8
1985 94.9 171.3 708.1 1172.6 1168.4 3315.3
1986 96.8 175.0 719.4 1188.4 1178.8 3358.5
1987 99.3 179.2 734.2 1205.9 1185.9 3404.5
1988 102.2 182.8 753.5 1230.5 1197.6 3466.7
1989 105.5 185.9 776.6 1257.8 1212.3 3538.0
1990 109.5 191.2 804.4 1279.9 1228.1 3613.0
1991 112.1 193.9 825.4 1290.7 1234.7 3656.7
1992 114.7 198.0 847.5 1313.6 1253.5 3727.3
1993 115.6 199.8 859.2 1321.9 1260.7 3757.1
1994 116.9 202.4 870.4 1329.9 1270.6 3790.1
1995 118.6 205.0 883.0 1344.2 1281.8 3832.7
1996 120.2 208.1 895.0 1358.3 1293.0 3874.6
1997 121.5 210.8 904.6 1372.9 1305.8 3915.6
1998 123.1 213.9 914.6 1387.0 1318.4 3957.0
1999 124.8 216.8 926.4 1403.2 1332.8 4003.9
2000 126.6 219.3 939.9 1420.7 1347.7 4054.2
2001 128.3 222.1 953.3 1438.2 1362.8 4104.8
2002 129.9 225.1 966.3 1454.4 1376.4 4152.2
Average Annual Growth Rates (%)
1980-1989 2.3% 2.3% 2.3% 1.7% 1.0% 1.6%
1990-1995 1.6% 1.4% 1.9% 1.0% 0.9% 1.2%
1996-2002 1.3% 1.3% 1.3% 1.1% 1.0% 1.2%
</TABLE>
* Variables used in the end-use forecast models.
"Regional ACCESS Handbook." DRl/McGraw-Hill. Inc., 1995.
29
<PAGE>
PACIFIC GAS and ELECTRIC COMPANY
ECONOMIC & DEMOGRAPHIC ASSUMPTIONS*
PG&E Electric Service Area and
Commercial Building Type
<TABLE>
<CAPTION>
COMMERCIAL COMMERCIAL COMMERCIAL COMMERCIAL COMMERCIAL COMMERCIAL
FLOORSTOCK FLOORSTOCK FLOORSTOCK FLOORSTOCK FLOORSTOCK FLOORSTOCK
Offices Restaurants Retail & Food Health Miscellaneous Total
YEAR (Msqft.) (Msqft.) (Msqft.) (Msqft.) (Msqft.) (Msqft.)
<S> <C> <C> <C> <C> <C> <C>
1980 274.0 14.8 236.0 51.7 554.7 1131.3
1981 275.0 15.1 239.9 52.6 563.1 1145.7
1982 264.8 15.5 244.6 54.0 567.6 1146.5
1983 275.0 15.7 249.3 54.9 575.4 1170.4
1984 283.5 16.0 253.7 56.0 587.3 1196.5
1985 291.2 16.3 257.7 57.0 599.4 1221.7
1988 288.7 16.7 262.9 58.8 611.7 1238.7
1987 300.6 17.1 266.7 60.5 623.5 1268.3
1988 318.3 17.6 269.6 63.3 637.6 1306.3
1989 325.4 18.1 274.1 65.3 648.9 1331.7
1990 329.5 18.6 277.7 68.0 659.9 1353.6
1991 329.0 19.0 283.8 70.2 672.9 1375.0
1992 320.7 19.4 289.2 71.8 686.4 1387.4
1993 321.0 19.9 294.7 73.1 701.1 1409.7
1994 328.2 20.3 300.2 74.8 715.6 1439.1
1995 333.8 20.9 307.6 76.8 734.2 1473.3
1996 339.4 21.5 312.7 78.6 750.6 1502.7
1997 344.8 21.9 316.9 80.3 765.1 1529.0
1998 350.2 22.4 320.8 81.8 778.5 1553.7
1999 355.6 22.8 324.7 83.3 791.2 1577.5
2000 360.7 23.1 328.5 84.8 803.2 1600.3
2001 365.5 23.5 332.3 86.1 814.7 1622.0
2002 369.9 23.8 336.0 87.4 825.7 1642.8
Average Annual Growth Rates (%)
1980-1989 1.9% 2.3% 1.7% 2.6% 1.8% 1.8%
1990-1995 0.3% 2.4% 2.1% 2.5% 2.2% 1.7%
1996-2002 1.4% 1.7% 1.2% 1.8% 1.6% 1.5%
</TABLE>
* Variables used in the end-use forecast models,
"Commercial Floorstock," F,W, Dodge Division, McGraw-Hill, Inc.,1994,
30
<PAGE>
<TABLE>
<CAPTION>
TCU Sector Model Input
Military Cooling
-------- -------
Employment Degree
---------- ------
Year (1,OOO's) Days
---- --------- ----
<S> <C> <C>
1980 44 169
1981 46 222
1982 47 121
1983 47 203
1984 48 304
1985 49 228
1986 49 204
1987 50 223
1988 49 264
1989 49 187
1990 48 214
1991 46 223
1992 46 228
1993 43 195
1994 40 202
1995 39 197
1996 38 269
1997 37 216
1998 36 216
1999 35 216
2000 35 216
2001 35 216
2002 34 216
Average Annual Growth Rates (%)
1980-1989 1.2 1.1
1990-1995 4.1 -1.6
1996-2002 -1.8 -3.6
</TABLE>
* All variables are used in forecast. Data source: WEFA
31
<PAGE>
PACIFIC GAS and ELECTRIC COMPANY
ELECTRICITY RATES by (SIC) SECTOR
(1995 cents/kWh)
<TABLE>
<CAPTION>
YEAR RESIDENTIAL COMMERCIAL INDUSTRIAL
<S> <C> <C> <C>
1980 93 10.3 70
1981 95 10.6 73
1982 113 12.5 90
1983 8.9 10.0 7.2
1984 9.6 10.7 7.5
1965 10.9 12.2 8.6
1986 10.5 11.7 7.6
1987 10.2 10.6 6.1
1986 10.9 10.3 5.7
1989 11.7 10.6 5.9
1990 12.0 10.7 5.8
1991 12.9 11.3 6.1
1992 12.7 11.3 6.0
1993 12.9 11.2 6.0
1994 12.6 10.8 6.0
1995 13.5 10.8 6.0
1996 11.6 9.6 6.3
1997 11.4 9.4 6.3
1998 10.0 8.8 6.3
1999 9.7 8.6 6.3
2000 9.5 6.4 6.3
2001 9.2 8.2 6.3
2002 8.7 6.7 5.1
Average Annual Growth Rates (%)
1980-1989 26% 0.3% -1.9%
1990-1995 23% 0.1% 0.6%
1996-2002 48% -5.8% -3.4%
</TABLE>
. Rates are deflated by the (chain-weighted) PCWGDP deflator, Rates
shown here may be different from short-term rates developed by PG&E.
32
<PAGE>
METHODOLOGY
33
<PAGE>
INTRODUCTION AND OVERVIEW
PG&E's load forecasting process is an integrated, disaggregated process used for
analyzing loads and the impacts of demand-side management programs, The process
uses several models to forecast and analyze loads, These models are:
1. Residential End-Use Energy Model.
2. Commercial End-Use Energy Model.
3. Industrial End-use/Econometric Energy Model.
4. Transportation/Communication/Utility (TCU) SIC Energy Model.
OVERVIEW OF THE FORECAST PROCESS
PG&E's load forecasting process is an integral part of PG&E's corporate planning
process, The load forecast is used for various pluming and budgeting activities,
including: (1) electric resource planning, (2) rate planning, (3) demand-side
management (DSM) planning, (4) electric operations, (5) fuels planning (6)
transmission and distribution planning, and (7) financial planning.
In addition to its internal uses, the load forecast is used to support filings
before various state and federal agencies, including the California Public
Utilities Commission (CPUC) and the California Energy Commission (CEC.) In
producing a forecast, a consistent set of economic, demographic and price
assumptions are input into the forecasting models, The forecasting models
incorporate data that have been collected and produced as part of PG&E's data
collection projects (e.g., appliance saturations and UECs).
The forecasting models discussed here produce forecasts of loads for PG&E's own
customers only. Customers' total load, however, includes loads met by purchases
from PG&E and loads met by self-generation. The models do not produce load
forecasts of WAPA, CCSF and other small customers that are in PG&E's Planning
Area. Forecasts of these entities' loads are not produced by these models
because:
1. PG&E's recorded SIC data includes SIC detail for PG&E's customers
only, not municipal utility customers: and
2. PG&E's estimates of appliance saturations and usage are for PG&E's
customers only, not for municipal utility customers.
Rather than introduce error into the end-use/SIC database by adjusting it to
include these customer's sales, PG&E's end-use models are based on and
calibrated to PG&E's customer data.
Sales by the other utilities to their customers are accounted for in the
forecast process by adding forecasts of their total sales to PG&E's total
customer load forecast. This sum is the forecast of the PG&E Planning Area.
34
<PAGE>
Additionally, PG&E's forecasting models do not simultaneously estimate portions
of load that are met by PG&E's own sales and portions of load that are met by
customers own generation. Evaluations and estimates of customers' own generation
are developed separately within PG&E.
Overview of the Major Forecasting Models
Residential:
- End-Use Model (18 end-uses, 1 household type)
- Total use = Sum over each end-use appliance (Households)
*Saturation (of end-use appliances in the household)
*Unit Energy Consumption (of each end-use appliance)
*Utilization Factor (short4erm response to energy prices.)
Commercial:
- End-Use Model (10 end-uses, 5 building types)
- Total use = Sum over each building type and end-use (Floorstock)
*Saturation (of end-use equipment in each building type)
*Unit Energy Consumption (of each end-use equipment)
*Utilization Factor (short-term response to energy prices.)
Industrial:
- End-Use Model (6 end-uses, 20 SIC groups)
- Total use = Sum over each SIC group and end use (output by SIC
group)
*Unit Energy Consumption per unit of output by SIC group, end
use)
*Fuel Share (SIC group, end use,)
TCU:
- Econometric Model (SICs 40,41,42,43, 44,45,47,48,49,7520-23)
- Ratio Technique (SIC 46), (SIC 97)
35
<PAGE>
DEMAND FORECAST METHODOLOGY
RESIDENTIAL SECTOR
Long term residential gas and electricity consumption is forecast using an end-
use mode] named EUPHORIA (North Bay Software, Inc., Copyright 1986). This model
explicitly calculates energy consumption of an average household for the
following appliances:
<TABLE>
<CAPTION>
Appliances/end-use and fuel:
<S> <C>
1. Central A/C* CZ I ** (electricity) 11. Pool Heater (gas)
2. Central A/C CZ 2 (electricity) 12. Water Heater (gas, electricity)
3. Central A/C CZ 3 (electricity) 13. Space Heater (gas, electricity)
4. Central A/C CZ 4 (electricity) 14. Room A/C (electricity)
5. Central A/C CZ 5 (electricity) 15. Evaporative Cooler (electricity)
6. Refrigerator (electricity) 16. Color TV (electricity)
7. Freezer (electricity) 17. Dishwasher (electricity)
8. Range (gas, electricity) 18. Clothes Washer (electricity)
9. Clothes Dryer (gas, electricity) 19. Lighting and Miscellaneous (gas, electricity)
10. Pool Pump (electricity)
</TABLE>
*Air Conditioner
**Climate Zone Number (California Energy Commission.)
Energy consumption is the product of service area
households, average appliance saturations and average unit energy
consumption (UEC) by end-use. The appliance saturations are adjusted
through time by the marginal saturations in new homes. Appliance
replacement rates and the different efficiencies of new appliances are
accounted for in UEC calculations. Adjustments for additional
conservation savings and appliance utilization are also accounted for
in the model.
Short-run changes in energy consumption are captured in the model through
utilization term. Utilization terms are included in each end-use equation to
capture short-run changes due to efficiency adjusted energy prices. These
changes have been restricted to space conditioning appliances and gas pool
heating, assuming that people change thermostat settings, but not other habits.
Long-ruin changes in energy consumption are captured in the
model by changes in appliance saturations and UECs, Saturations
capture the long-run adjustment of appliance stock to income and
energy prices. UECs capture the long-run adjustment of appliance usage
to energy prices, efficiency improvements and conservation programs.
Average saturation rates are a weighted avenge of average
saturations in a previous period and marginal (new household)
saturations in the current period. Base year (1991) average saturation
rates are based on PG&E's 1990 Residential
36
<PAGE>
Appliance Saturation Survey (RASS) results. Marginal saturations are
based on the 1991 PG&E New Homes Survey.
Average unit energy consumption is calculated in the same manner as saturations
for all enduses. Base year (1991) UECs are derived using conditional demand
analysis. Data from PG&E's 1990 RASS, together with billing and weather
information, are used in this analysis. Marginal UECs are expressed as
percentages of 1991 base values.
Dwellings are represented as an average of all dwelling
types and are forecast for five CEC climate zones. An initial decay
rate of 2 percent, increasing to 4 percent by 2005, is assumed. A 2
percent rate implies an average dwelling life of 50 years. The higher
decay rate in the later pan of the forecast period reflects a large
building boom which occurred in the I 950s resulting in a higher
building decay rate in the later part of the forecast period. The
decay rate is assumed to fall to 3 percent after 2010.
Appliance life and decay rates are based primarily on market
research and consumer report information.
37
<PAGE>
38
<PAGE>
Below is a detailed listing of the variables and formulas
used in the model.
Notation: In the following equations, brackets [ ] &e used
to indicate "subscripts," or particular elements of a vector or array.
The following subscripts are used frequently: t = this year, eu= this
end-use, f= this fuel. For example, CIP[t] means "Percentage Change in
Price for year t."
Abbreviations used in formulas:
ActS Actual Sales
AD Average Decay Rate of Appliances
ADR Annual Decay Rate of Housing Stock
AS Average Saturation
AUEC Average Unit Energy Consumption
C Conservation
CIP Percentage Change in Fuel Price
CPNS Computed Percentage of New Stock
Cu End-Use (the one being calculated)
f Fuel (the one being calculated)
FS Forecast Sales
HS Household Stock
IF Income Elasticity
IHH Income per Household
ME Miscellaneous Electric
MiS Miscellaneous Sales
MS Marginal Saturation
MUEC Marginal Unit Energy Consumption
PE Price Elasticity
Scale Scaling Factor
U Utilization
t Time (Year) (the one being calculated)
CPNS: Computed Percentage of New Stock (by End-Use and Year)
Year 1: CPNS[eu][1] = 0
Years 2-25: CPNS[eu][t] = AD[eu] + HS[t] - (1-ADR[t-l])(HS(t-l]))IHS[t]
AS: Average Saturation, by fuel, end-use and year
Year 1: AS[f)[eu][l] = MS[f][eu] [l]
Years 2-25: AS[fl[eu][1] = AS[f][eu][t-l] + CPNS[eu][t] * (MS [f][eu][t]
- AS[f](eu] [t-1]
39
<PAGE>
where
Mst = (HStt* AD *ASt,i +MSt* HS t (ADR t-1) * HS t-1))/(HS * AD
+(HS t-(1-ADRt-1,) * HSt-1))
Average Unit Energy Consumption, by fuel, end-use and year
AUEC[fl[eu][l] = MUEC[fl[eu][I]
AUEC[fl[eu]ft] = AUEC[fl[eu][t-1] + CPNS[eu][t] * MUEC[fl[eu]ft]
- AUEC[f][eu][t-l]
For the "Miscellaneous Electric" end-use, AUEC is calculated
differently, using coefficients estimated by conditional demand
analysis,
Year 1: AUEC[fl[ME][1] = Misc., Electric Base
Years 2-25: AUEC[fl[ME][t] = 1140 + 23*IHH[t]
= (.5*CIP[t]*AUEC[f]Ceu]][t-1])
U: Utilization, by end-use and year
Year l: U[eu][l]=l
Years 2-25: U[eu] [t[ = U[eu][t-1] * (1 ICIPW*PE[eu]y(AUEC[t 1]/AUEC[t])
C: Utility-sponsored Conservation, by end-use and year
Years 1-2: C[f] [eu][t] = 0
Years 3-25: C[f] [eu][t] = exogenous forecast
ES: Energy Sales, by fuel, end-use and year
ES[f~[eu][t~ = (HS[t~ * AS[fj[eu][t] * AUEC[f] l[eu][t]/1000
- C[fl[eu][t]) * U[e][t] * Scale[f]
Note: The Scale parameter used in the calculation of energy
sales puts sales results into the proper reporting units. It is needed
because the units obtained by multiplying through the various
quantities in the equation may not be the desired reporting units.
FS: Forecast Sales, by fuel and year
FS[fj[t~ = S ES[f][eu][t]eu
40
<PAGE>
COMMERCIAL SECTOR
Long-term commercial gas and electric energy consumption is forecast using an
end-use model named COMMEND-PC 3.2 (EPRI-sponsored model by Regional Economic
Research, Inc., 1992). The commercial end-use model explicitly calculates energy
consumption for the following end-uses and commercial building types:
Equipment/end-use and fuel:
1. Space Heating (gas, electricity) 6. Refrigeration (electricity)
2. Space Cooling (gas, electricity) 7. Exterior Lighting (electricity)
3. Ventilation (electricity) 8. Interior Lighting (electricity')
4. Water Heating (gas, electricity) 9. Office Equipment (electricity)
5. Cooking (gas, electricity) 10. Miscellaneous (gas, electricity)
Building type and location:
COASTAL AREA INLAND AREA
------- ---- -----------
1. Offices 2. Offices
3. Restaurants 4. Restaurants
5. Retail-Food 6. Retail-Food
7. Health 8. Health
9. Miscellaneous 10. Miscellaneous
Energy consumption is the product of service area floorstock (organized by
building type and climate area shown above), average end-use equipment
saturation and average unit energy consumption by end-use. (The commercial
sector acronym for average unit energy consumption is EUI for Energy Utilization
Index.) End-use equipment saturations are adjusted through time by marginal
saturations in new buildings. Equipment replacement rates and the different
efficiencies of new equipment are accounted for in EUI calculations. Adjustments
for additional conservation savings and equipment utilization are also accounted
for in the model.
Short-run changes in energy consumption are captured in the model through
utilization terms. Utilization terms are included in each end-use equation to
capture short-run changes due to efficiency adjusted energy prices, weather
effects (heating/cooling degree-days) and operating hours.
Long-run changes in energy consumption are captured in the model by changes in
end-use equipment saturations and EUIs. Equipment saturations capture long-run
adjustments of equipment stock to capital costs and energy prices. EUIs capture
long-run adjustments of equipment usage to energy prices, efficiency
improvements and conservation programs.
Average saturation rates are a weighted average of average saturations in a
previous period and marginal (new building) saturations in the current period.
Base year (1975) average saturation rates are based on a
41
<PAGE>
CEC analysis of PG&E's 1982 Commercial End Use Mail Survey, 1985 On-Site Survey
and 1988 Commercial End Use Mail Survey. Results of the CEC analysis are
published in the CEC ER92R Report of California Energy Demand, Volume II, dated
June 1991. The results of PG&E's 1993 Commercial On-Site End Use Survey are also
included as more recent data for model updating. Floorstock-weighted adjustments
area made to these survey data to aggregate to the building types listed above.
Average unit energy consumption is calculated in a similar manner as saturations
for all end-uses. Base year (1975) EUIs are based on a CEC-funded on-site survey
(see Hittman Associates Inc., 1980 and Weatherwax, R. K., July 1980) using
conditional demand and Department of Energy (DOE-2) Heat Load Modeling analysis.
The base year 1975 was chosen by the CEC Staff (and more recently by PG&E)
because it occurs prior to the application of mandatory building standards. The
impacts of 1978, 1984 and 1992 mandatory building and equipment standards are
then modeled in DOE-2 and used as modifications of these 1975 base year EUIs.
Additionally, the above PG&E survey results are used as more recent data for
model updating. Floorstock-weighted adjustments area made to these survey data
to aggregate to the building types listed above.
Commercial floorstock is a major component used to determine equipment stock,
and is therefore a primary driver in the forecasting model. Commercial
floorstock is divided into three major parts, base year floorstock, historic
floorstock and forecast floorstock. Floorstock is represented as an average of
all building types and is aggregated into two major climate areas (PG&E's
coastal area and inland area.)
Base year (1975) occupied floorstock and the historic floorstock data set are
obtained from California county tabulations of commercial floorstock and vacancy
rates by F.W. Dodge Division. McGraw-Hill, Inc., (updated in 1994,) Forecast
estimations of commercial floorstock use ordinary' least squares regression
analysis (in linear form) of floorstock and applicable forecast driving,
variables of California Metropolitan Statistical Areas from DRI Inc.,
Long term commercial gas and electricity consumption is forecast by explicitly
calculating the energy consumption of multiple building types and multiple end-
uses. For each building type and end-use combination, energy consumption is
forecast using a central energy equation, which is the product of the stock of
commercial floorstock times the end-use equipment saturation of the floorstock,
times the unit energy consumption rate of the end-use equipment, times the
equipment utilization rate. The central end-use energy equation is as follows:
Central End-Use Energy Equation:
10, 40, 10, 3
Consumption (b,f) = Z(FST,b,v) * (SAT,b,v,eu,f) * (EUI,b,v,eu,f)
* (UTL,b,v,eu,f)
b,v,eu,f= 1
42
<PAGE>
Where:
b building type
v vintage (time)
eu end-use (the one being calculated)
f fuel (gas, electricity, other)
FST FLOORSTOCK (considers average floorstock, new completions,
decay rates and vacancy rates),
SAT SATURATION (considers average and new building saturations of end-
use equipment modified by multinominal logit equations, which evaluate
cost trends of each equipment system),
EUI ENERGY UTILIZATION INDEX (similar to Unit Energy Consumption)
(considers avenge and new building Furs of end-use equipment modified by
multinomial logit equations which evaluate equipment system life cycle
costs, the application of efficiency trends, cost trends, and mandatory
standards),
UTL UTILIZATION (considers short-run modifications to energy usage
levels due to changes in real energy prices, weather conditions and
operating hours),
Short-run gas price elasticities for each building type and end-use
combination are assessed to be between -0.07 and -0.04 for all building
types using price sensitive end-uses of space heating, space cooling and
water heating and -0.01 for all building types and other equipment of
cooking and miscellaneous end-uses.
Short-run electricity price elasticities for each building type and end-
use combination are assumed to be between -0.07 and -0.04 for all
building types using price sensitive end-uses of space heating, space
cooling and water heating and -0.01 for all building types and other
equipment of cooking and miscellaneous end-uses.
43
<PAGE>
INDUSTRIAL SECTOR
Industrial energy requirements are forecasted using EPRI's PC-based Industrial
End Use Model (INFORM). INFORM forecasts gas and electric use for motors,
lighting, HVAC and thermal and other process use for each of the two digit SIC
manufacturing industries. The relatively small energy usage in the milling and
construction industries is forecasted to remain constant at historical levels.
Gas use for enhanced oil recovery (FOR) is forecasted using market information
obtained by PG&E marketing staff Incremental impacts of company DSM programs are
subtracted from the forecast, For the electricity forecast, only impacts of
committed DSM programs are subtracted; for the gas forecast, impacts of both
committed and anticipated programs are subtracted.
INFORM Model Structure
For each of file forecast period and for each end use and industry. INFORM
calculates the energy requirement per unit of industry output, the share of each
fuel and equipment type used to deliver that energy to the process and the fuel
input required to provide the required process energy. The level of detail and
complexity of equipment choice varies by end use. The forecast is driven by
industrial production. Equipment choices and energy intensities depend on prices
and efficiency standards.
The following end uses are modeled in INFORM
Motors (Electric)
Pumps, fans, compressors
Material handling
Material processing
Thermal Processes (Electric, Gas)
Melting
Heating
Drying and curing
Other Processes
Electrolytics (Electric)
Process steam (Gas)
Lighting (electric)
HVAC
Space heating (Gas)
Air conditioning (Electric)
44
<PAGE>
Miscellaneous
Gas
Electric
Each of the models is briefly described below,
Motors
The motor module forecasts the stock of motors, measured in total horsepower, by
end use, size class, efficiency level and load characteristics. The stock of
motors for each industry' and end use depends on the required horsepower per
unit of output capacity and the forecast of capacity. .Average annual operating
hours of the motor stock depends on the capacity utilization rate. The choice of
efficiency level of new or replacement motors depends on a life cycle cost
calculation and any constraints imposed by efficiency standards.
Thermal and Other Processes
- ---------------------------
The thermal and other processes modules forecast energy requirements based on
the required energy (in Btu's) per unit of output for each industry and end use,
the share of each type of equipment or fuel used to deliver that energy, and the
energy input required for each Btu of energy: delivered to the process,
Lighting
- --------
The lighting module, like the motor module, forecasts the stock and energy using
characteristics of the stock of lamps and fixtures. Total lumen requirements for
each industry depend on the lumens required per unit of output capacity and the
forecast of total capacity. Changes in the shares of lamp and fixture types are
based on life cycle cost calculations and constraints imposed by efficiency
standards. Operating hours depend on the forecasted capacity utilization rate,
HVAC
- ----
The HVAC module forecasts energy use for heating and cooling for each industry.
As in the thermal and other process modules, total energy required depends on
energy required per unit of output and the forecast of output, the shares of
each fuel or equipment type, and the conversion efficiency of input energy.
Miscellaneous
- -------------
For each industry and fuel type, miscellaneous energy use depends on the energy
required per unit of output and the forecast of output.
For a more detailed description INFORM, see Electric Power Research Institute,
User's Guide for INFORM 1,2, RP2217-4, August1993,
45
<PAGE>
DEMAND FORECAST METHODOLOGY
TCU SECTOR
The Transportation, Communications, Utilities and National Defense (TCU) Model
encompasses SICs 4049, SICS 7520-25, and 97 with the following exceptions: SIC
422-Warehousing is modeled in the commercial sector; resale, interdepartmental
and public authority forecasts are obtained exogenously. Electricity demand in
the TCU sector is forecast using both econometric and ratio techniques.
The SICs are defined as follows:
Code Title
---- -----
40 Railroad Transportation
41 Local and Interurban Passenger Transit
42 Trucking and Warehousing
43 U,S, Postal Service
44 Water Transportation
45 Transportation by Air
46 Pipelines, except Natural Gas
47 Transportation Services
48 Communication
49 Electric, Gas and Sanitary Services
7520-25 Parking Ganges
97 National Security and International Affairs
The modeling methodology for each SIC is described below:
SIC 97 is forecast wing the ratio of total historic electric demand and
explanatory variable, The method of calculating the ratio for the SIC follows:
SIC 97
- ------
Annual total electric demand in SIC (1995) = 330.0 GWh
Service area annual employment for military (1995) = 38.9 thousands
Ratio = 330.W38.9 = 8.48 GWh per thousand employees
This ratio is then multiplied by forecasted employment to derive a
long-term electric demand forecast,
SIC 40,41,42,43,44,45, 46,47,48,49, 7520-25
These SICS are forecast by linear regressions of electric demand on cooling
degree days, and historical electric demand.
46
<PAGE>
GLOSSARY OF VARIABLE NAMES
BART ANNUAL ELECTRIC ENERGY CONSUMPTION FOR BART
BIN42 BINARY VARIABLE FOR 1988 AND 1989 - OFFSET A DROP IN ENERGY
CONSUMPTION FOR SIC 4212
BIN4457E BINARY VARIABLE FOR S1C44, 45 AND 75
PECDDBLM80 COOLING DEGREE DAYS BY BILLING BASIS-80/0/F BASE
47
<PAGE>
ECONOMETRIC EQUATIONS
SIC40
- -----
LOG(SIC40E)= 0.80346 * LOG(SIC4OE)[-l~ + 0.73098
(7.21291) (1.73065)
SIC41
- -----
LOG(SIC41E) = 0.37571 * LOG(SIC4IE)[-l~ + 0.00267 * BART + 7.32278
(2.79312) (6.54430) (8.69087)
AR_0 = +0.93058*AR_1
(13.0378)
SIC 42
- ------
LOG(SIC42E)= 0.29549 * LOG(S1C4213)[-1~ + 0.00075 * PECDDBLM8O
(2.03971) (1.88500)
+ 0.16990 * BIN42 + 2.67331
(4.58709) (4.42178)
SIC 43
- ------
LOG(SIC43E) = 0.99574 * LOG(51C43E) [-1~.+ 0.00038 * PECDDBLM8O - 0.01866
(16.0141) (1.31521) (0.05968)
LOG(SIC46E) = 0.%551 * LOG(S1C46E)[-1~ + 0.00125 * PECDDBLM8O
(13.1164) (1.49389)
-0.15768 *BIN46 + 0.16295
(1.19627) (0.31457)
SIC 48
- ------
LOG(SIC48E) = 0.81978 * LOG(SIC48E)[-1] + 1.18644
(8.32443) (1 86814)
SIC 49
- ------
LOG(SIC49E) = 0.89498 * LOG(51C49E)[-1] + 0.00081 * PECDDBLM8O + 0.62364
(15.1246) (2.84403) (1.43150)
SIC 44.45.47. AND 7520-25
- -------------------------
LOG(S1C4457E) = 0.51424 * LOG(S1C4457E)[-1] +0.08407 * B1N4457E +2.56931
(2.89237) (2.70860) (2.68536)
48
