EXHIBIT 10.2
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Subject to Rule 51 of the CPUC Rules of Practice and Procedure, Rule 601 et
seq. of the FERC Rules of Practice, Rule 408 of the Federal Rules of Evidence,
and Section 1152 of the California Evidence Code
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[GAS ACCORD LOGO]
THE GAS ACCORD SETTLEMENT AGREEMENT
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I. INTRODUCTION
A. PROPOSAL FOR A NEW GAS MARKET STRUCTURE FOR NORTHERN CALIFORNIA
The Gas Accord is a proposal to significantly restructure the way PG&E
provides natural gas service to California consumers by increasing
competition and customer choice. In part, the Gas Accord is a response to
signals from regulators and the market that the time has come for such
changes. The Gas Accord is also a vision of how the natural gas industry
in northern California should be structured as we enter the next century.
The Gas Accord consists of three broad initiatives. First, the Accord
unbundles PG&E's gas transmission and a portion of storage services, places
PG&E at risk for these costs, and changes the terms of service and the rate
structure for gas transportation so that customers' rates more accurately
reflect the facilities used to serve them. PG&E's service area is served by
an integrated high-pressure transmission system that resembles an
interstate pipeline system more than a typical local distribution company
(LDC) system. The Accord unbundles the transmission system, and requires
PG&E to operate and provide service on that system similar to an interstate
pipeline. PG&E will continue to provide distribution service, much as it
does today.
Second, the Accord changes PG&E's role in procuring gas supplies for core
customers in order to increase customer choice. It reduces PG&E's role in
core procurement, and reduces PG&E's holdings of interstate transportation
capacity. It also provides for negotiations between PG&E and California gas
producers for a mutual release of supply contracts with PG&E. PG&E's core
procurement department will continue to hold a portion of storage capacity
to ensure system reliability and a defined standard of customer service
reliability, but customers will be free to seek commodity and transmission
services from alternative suppliers. As part of this Agreement, the Core
Procurement Incentive Mechanism agreed to by PG&E and DRA in 1996 must be
implemented for an initial period through 1997, followed by the revised
incentive mechanism described in the Gas Accord for the period thereafter.
The Gas Accord period will extend from the date of implementation, which
PG&E is asking to be July 1, 1997, through December 31, 2002.
Third, the Gas Accord settles all major outstanding gas regulatory issues.
Neither PG&E, the CPUC, nor market participants can expend the energy and
resources to proceed with the Gas Accord while at the same time arguing
about whether PG&E acted reasonably under the old rules.
The changes proposed herein are reasonable and bold responses to several
forces for change that have manifested themselves since gas restructuring
began in California, about ten years ago. On the regulatory side, the CPUC
has initiated programs to segment the noncore from the core market, with
rights accorded to noncore customers to obtain transmission service and
commodity supplies separately from bundled PG&E service. Core customer
representatives are now advocating an increase in the competitive choices
available to them. In addition, the CPUC has changed the way it regulates
both Southern California gas utilities, approving performance-based
regulation for each utility's gas procurement. The CPUC also has called for
an OII/OIR for the purpose of further restructuring the California natural
gas industry on at least two occasions, most recently in a decision (D.94-
02-042) approving interim rates for PG&E's Pipeline Expansion Project.
The market, too, has signaled a desire for change. Customers have sought
more options for natural gas transportation and sources of supply.
Marketers and producers have stated there are obstacles to selling directly
to core customers, and there have been proposals to build competitive
pipelines into PG&E's service area. All of these demonstrate that PG&E's
current transportation and service structure is outdated.
For these reasons, further changes are inevitable. PG&E could resist and
watch these changes occur piecemeal, to the possible disadvantage of its
customers and shareholders; however, this Gas Accord, negotiated with the
market participants, offers a better prospect for a rational result. All
participants in the Accord process -- market participants, the CPUC, and
PG&E -- have significant interests in the process of change. It is vital
that this process result in a fair resolution of past issues and a fair
opportunity to compete in the new world of unbundled competitive gas
markets.
Unbundling of services will increase market participation. Each competitive
market -- transmission, procurement, and other services --inevitably will
lead to the development of new services and increased choices for
consumers. As these markets become contested by new service providers, the
freedom to compete in each on an equal basis must be granted to all
parties, including PG&E. The Accord will move PG&E and the marketplace
toward this vision.
The Accord is a negotiated compromise on a number of issues related to many
proceedings. If not accepted by the Commission, the Accord shall not be
admissible in evidence in this or any other proceeding. Nothing contained
herein shall be deemed to constitute an admission or an acceptance by any
party of any fact, principle, or position contained herein.
The Accord is to be treated as an entire package and not as a collection of
separate agreements on discrete proceedings, nor is the restructuring
proposal separable from the resolution of past issues. To accommodate the
interests of different parties on diverse issues, changes, concessions, or
compromises in one section of the Accord necessitated changes, concessions,
or compromises in other sections.
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In an August 16, 1995, Assigned Commissioner's Ruling on the Gas Accord
process, Assigned Commissioner Fessler stated:
I encourage all affected parties to participate in settlement
discussions, and I encourage PG&E to include all gas market
participants in its negotiations. I look with disfavor on parties that
decline fair opportunities to participate in settlement discussions,
then criticize agreements reached in their absence. (August 16, 1995,
ACR, p. 5).
The Gas Accord negotiations have met the Assigned Commissioner's standard
for wide participation, and the Accord presents a new, more competitive
structure for the natural gas marketplace in northern California that is
broadly supported by the market participants. The settling parties
encourage the Commission to adopt and implement the Gas Accord.
B. ELEMENTS OF THE AGREEMENT
1. Unbundle the rates and service options for transmission system service
from distribution system service. The transmission system is defined as
PG&E's backbone and local gas transmission lines, including gathering
and Stanpac facilities. The local transmission system includes
distribution feeder mains (DFMs). A map of PG&E's system is included at
the end of this Section.
2. Charge transmission, storage, and distribution rates to those customers
who use these facilities pursuant to contractually-defined terms of
service.
3. Provide balancing service through a single integrated gas system for
both transmission level and distribution level customers. PG&E proposes
initially to continue a monthly balancing service, with imbalance
trading, tighter tolerance bands and monthly cash-out provisions.
4. Establish transmission system services that eliminate the crossover ban
and the backbone credit.
5. Offer various paths over the transmission system. Each path requires a
separate contract. See Section II for more information on the
definition of the paths and applicable delivery and receipt points.
These paths include:
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a. Malin to On-system for the Core;
b. Malin to On-system;
c. Topock to On-system;
d. California Production and Storage to On-system;
e. Malin to Off-system;
f. Topock to Off-system;
g. California Production, Storage, Market Center/Hub Services, and On-
system Delivery Points to Off-system; and
h. G-XF Firm Service.
On-system is defined as any point at which deliveries are made to, or
for ultimate delivery to, PG&E's distribution facilities, PG&E's
storage facilities, a third party's storage facilities located in
PG&E's service territory, or end-use or wholesale loads located in
PG&E's service territory. Off-system is defined as any point of
interconnection for delivery outside of PG&E's service territory.
6. Provide new services over these paths using (a) Line 300 capacity, and
(b) capacity consisting of that portion of Line 400 capacity not
reserved for the core and that portion of Line 401 capacity not
reserved under long-term firm contracts with existing firm Expansion
shippers. This combined Malin capacity is to be redesignated by the
Commission as non-Expansion capacity, which shall be subject to phased-
in rates and shall not be subject to the tariff or contract provisions
and rights that apply to the Line 401 capacity reserved under long-term
Expansion contracts.
7. For ratemaking purposes, phase-in the embedded cost of 375 MMcf/d (381
Mdth/d) of Line 401 capacity into the Line 400 capacity not reserved
for the core over the period from 1997 through 2002. The phase-in will
begin at 200 MMcf/d (203 Mdth/d). This phase-in schedule is consistent
with historical Line 401 on-system usage and projected on-system
noncore demand growth. This will determine the Malin to on-system path
costs. (See Section II.I.3 for the complete phase-in schedule.)
8. Provide to the retail core 600 MMcf/d (609 Mdth/d) and to core
wholesale 6.5 MMcf/d (6.6 Mdth/d) of Malin to on-system vintage firm
capacity, at Line 400 embedded cost (vintaged rates). Any additional
capacity from Malin used by the retail core or wholesale customers must
be on the Malin to on-system path.
9. Honor the service commitments set forth in existing long-term
transmission service agreements for the period of the Accord or the
remaining term of each such
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agreement, whichever applies. These commitments are addressed below in
Section II.F.
10. Provide parking and lending services at all interstate interconnection
points and at Kern River Station. These services shall be provided
using transmission and storage capacity as it becomes available.
11. Continue operational integration of PG&E's gas storage facilities with
PG&E's transmission facilities. PG&E will reserve firm storage capacity
for pipeline balancing services and PG&E's Core Procurement Department
will contract for a major portion of PG&E firm storage capacity on
behalf of the retail core. The remaining storage capacity will be
marketed in an unbundled storage program.
12. Unless otherwise stated in this document, the principles and specific
elements of the Accord, the resulting Accord rates (and their
underlying assumptions) and the revenue treatment for Accord services
are fixed and not subject to challenge or change in any regulatory
forum during the Gas Accord period. Consequently, the parties will not
challenge any assumption that is set by this Accord, and that if
altered, would result in a shift of revenue responsibility between core
and noncore customers and/or between customers and PG&E shareholders.
Furthermore, any issue settled as part of the Gas Accord described in
Section V, Litigation Resolution, will not be subject to litigation in
any regulatory forum.
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This page left deliberately blank for the map to be inserted
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II. TRANSMISSION AND STORAGE SERVICES
A. NEW TRANSMISSION SERVICES
The services offered over the backbone portions of the new transmission
paths (paths a through g, listed in Section I.B.5 above) are described
below. Contracts will set the terms of service, including service
priority. Local transmission costs are included in a separate local
transmission charge, which will be collected from all on-system end-
users. The pre-existing transmission services are described in Section
II.B, below.
The following five transmission services will have all terms and
conditions set by tariff.
1. Firm Annual On-system (AFT)
a. Definition: Firm service on the transmission system with
deliveries on-system.
b. Minimum Term: One year.
c. Rate: Straight Fixed Variable (SFV) or Modified Fixed Variable
(MFV), at the shipper's option for the backbone component. See
rates in Section VI. No discounts.
2. Firm Seasonal (SFT)
a. Definition: Firm seasonal service on the transmission system.
b. Conditions: Paths to on-system destinations only. Maximum term
limited to two years.
c. Minimum Term: Three consecutive months in one season.
d. Winter Season: November through March.
e. Summer Season: April through October.
f. Rate: SFV or MFV, at the shipper's option for the backbone
component. See rates in Section VI. No discounts.
3. As-available On-system (AA)
a. Definition: As-available service on the transmission system
with deliveries on-system.
b. Minimum Term: One day.
c. Rate: Volumetric for the backbone component. See rates in
Section VI. No discounts.
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4. Firm Annual Off-system (AFT-Off)
a. Definition: Firm service on the transmission system with
deliveries off-system.
b. Minimum Term: One year.
c. Rate: Straight Fixed Variable (SFV) or Modified Fixed Variable
(MFV), at the shipper's option for the backbone component. If a
shipper elects SFV rate design, the shipper can also specify an
alternate delivery point on-system. If a shipper elects MFV,
delivery must be off-system only. See rates in Section VI. No
discounts .
5. As-available Off-system (AA-Off)
a. Definition: As-available service on the transmission system
with deliveries off-system.
b. Minimum Term: One day.
c. Rate: Volumetric for the backbone component. See rates in
Section VI. No discounts.
The following four transmission services are negotiable, as indicated.
6. Negotiated Firm Service On-system (NFT)
a. Definition: Firm service on the transmission system with
deliveries on-system.
b. Minimum Term: Negotiable.
c. Rate: Negotiable, above a marginal-cost-based floor consistent
with negotiated term. Maximum rate for the backbone component
of each path is 120 percent of the firm annual rate for that
path.
d. Take Requirement: Negotiable.
e. Sections IX and X of General Order No. 96-A are waived by the
Commission.
7. Negotiated As-available On-system (NAA)
a. Definition: As-available service on the transmission system
with deliveries on-system.
b. Minimum Term: Negotiable.
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c. Rate: Negotiable, above a marginal-cost-based floor consistent
with the negotiated term. Maximum rate for the backbone
component of each path is 120 percent of the As-available rate
for that path.
d. Take Requirement: Negotiable.
e. Sections IX and X of General Order No. 96-A are waived by the
Commission.
8. Negotiated Firm Service Off-system (NFT-Off)
a. Definition: Firm service on the transmission system with
deliveries off-system.
b. Minimum Term: Negotiable.
c. Rate: Negotiable, above a marginal-cost-based floor consistent
with negotiated term. Maximum rate for the backbone component
of each path is 120 percent of the firm annual rate for that
path.
d. Take Requirement: Negotiable.
e. Sections IX and X of General Order No. 96-A are waived by the
Commission.
9. Negotiated As-available Off-system (NAA-Off)
a. Definition: As-available service on the transmission system
with deliveries off-system.
b. Minimum Term: Negotiable.
c. Rate: Negotiable, above a marginal-cost-based floor consistent
with the negotiated term. Maximum rate for the backbone
component of each path is 120 percent of the As-available rate
for that path.
d. Take Requirement: Negotiable.
e. Sections IX and X of General Order No. 96-A are waived by the
Commission.
10. PG&E may also offer other customer-specific negotiated contracts.
Negotiated transmission service contracts under NFT and NAA will
not require submission to the CPUC for approval; however, any other
negotiated transmission service contracts will require submission
to the CPUC for approval.
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11. The following table summarizes which new transmission services are
available to the transmission paths described in Section I.B.5.
Available
Path Services
---- ---------
a. Malin to On-system for Core AFT
b. Malin to On-system AFT, SFT, AA, NFT,
NAA
c. Topock to On-system AFT, SFT, AA, NFT,
NAA,
d. California Production and AFT, SFT, AA, NFT,
Storage to On-system NAA,
e. Malin to Off-system AFT-Off, AA-Off,
NFT-Off, NAA-Off
f. Topock to Off-system AFT-Off, AA-Off,
NFT-Off, NAA-Off
g. California Production, Storage, AFT-Off, AA-Off, Services and
Market Center/Hub On-system NFT-Off, NAA-Off
Delivery Points to Off-system
B. PRE-EXISTING TRANSMISSION SERVICES
1. G-XF Firm Service
a. Definition: Firm service on Line 401 under the G-XF rate.
b. Minimum Term: Thirty years.
c. Rate: Incremental rates based on a capital cost for Line 401 of
$736 million, using utility capital structure and the operating
expenses and cost allocation methodologies set forth in PG&E's PEPR
Application.
d. Take Requirement: As negotiated.
e. Other terms and conditions: Delivery point as set forth in Exhibit
A to each firm contract; Uniform Terms of Service rights apply only
to firm G-XF service; backbone credit and crossover ban are
eliminated.
f. Sections IX and X of General Order No. 96-A may apply.
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2. Expedited Application Docket (EAD) Agreements
a. Definition: Firm service on Line 300 and from California gas
production to the burnertip, under individually negotiated
contracts approved by the CPUC under the provisions of Decision 92-
11-052.
b. Minimum Term: As set forth in each contract.
c. Rate: Volumetric negotiated rate, as set forth in each contract.
d. Take Requirement: As set forth in each contract.
e. Other terms and conditions: As set forth in each contract.
f. Sections IX and X of General Order No. 96-A may apply.
3. Enhanced Oil Recovery (EOR) Agreements
a. Definition: Interruptible service for Enhanced Oil Recovery
customers pursuant to Decisions 85-12-102 and 87-05-046.
b. Minimum Term: As set forth in each contract.
c. Rate: Volumetric negotiated rate, as set forth in each contract.
d. Take Requirement: None
e. Other terms and conditions: As set forth in each contract.
f. Sections IX and X of General Order No. 96-A apply.
4. Expedited Direct Connection Docket (EDCD) Agreements
a. Definition: Agreements for direct connection service on PG&E's Line
401 approved pursuant to the CPUC's Expedited Direct Connection
Docket.
b. Term: The remaining term of the direct connection agreement.
c. Rate: The rate established in the direct connection agreement. If
this agreement does not specify a rate, then the rate will be
established under one of the new transmission service rates.
d. Other terms and conditions: Per the direct connection agreement, or
if unspecified in that agreement, the applicable Gas Accord
tariffs.
5. Other Existing Agreements
a. Negotiable Interruptible Agreements
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PG&E has a number of negotiable interruptible transportation
agreements with terms that may extend into the Accord period. PG&E
will continue to honor the terms and conditions, including the
rate, negotiated for the original term of these contracts.
b. Crockett Cogeneration
Crockett cogeneration has a negotiated contract which provides for
transportation service at volumetric rates. PG&E will continue to
honor the terms and conditions, including the rate, negotiated for
the original term of this contract. If any terms and conditions are
unspecified by the existing contract agreement, then the applicable
Gas Accord tariffs will apply.
C. STORAGE SERVICES
1. Storage Capacity Allocated To Core Customers, Including Core Transport
Customers
a. Core service is allocated a portion of storage capacity to support
the obligation to maintain highly reliable service under cold
conditions. See Section II.E.5 for allocations.
b. Core aggregators, on behalf of their core transport customers, will
be allocated a pro rata share of the total core reservation based
on the winter season throughput of their core customers.
c. Costs for storage allocated to core customers, including core
transport customers, will remain bundled in all core rates.
d. Any storage capacity that is not needed for core reliability may be
brokered.
e. PG&E and core aggregators, on behalf of core customers, may elect
to purchase more storage through the unbundled storage program.
2. Storage Capacity Allocated to Pipeline Balancing Services
a. A portion of storage capacity is needed to support the balancing
services. See Section II.E.5 for the allocation.
b. Storage costs allocated to balancing services remain bundled in
transmission rates.
3. Unbundled Storage Program
a. PG&E will offer storage services to the market from its integrated
storage facilities through the unbundled storage program. The
storage services will be
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offered from the capacity remaining, after the allocations for
balancing provisions and storage for the core market.
b. Firm Storage Service (FS)
i. Definition: Firm storage service.
ii. Minimum Term: One year
iii. Rate: Sub-functions are capacity (combined injection and inventory)
and withdrawal. Each sub-function is further divided into a
reservation charge (fixed) component and a volumetric charge
(variable) component.
iv. Conditions: Requires injection during the defined summer storage
season.
v. Features: Imbalance trading and inventory transfers are available.
c. Negotiated Firm Storage Service (NFS)
i. Definition: Firm storage service; customers may purchase inventory,
injection, and withdrawal separately.
ii. Minimum Term: One month
iii. Rate: The flexibility inherent in this storage offer could result
in stranded facilities and PG&E requires the opportunity to collect
the value of its storage services. Rates are negotiable above a
short-run marginal price floor and capped at the price which will
collect 100 percent of PG&E's total revenue requirement for the
unbundled storage program for each of the three storage
subfunctions (e.g., inventory, injection, or withdrawal).
iv. Features: Imbalance trading, inventory transfers, and counter-
cyclical operations are available.
v. Sections IX and X of General Order No. 96-A are waived by the
Commission.
d. Negotiated As-available Storage Injection and Withdrawal Service (NAS)
i. Definition: As-available storage service only available to
customers with firm storage inventory.
ii. Minimum Term: One day
iii. Rate: Volumetric only rate design. The flexibility inherent in this
storage offer could result in stranded facilities and PG&E requires
the opportunity to collect the value of its storage services. Rates
are negotiable above a marginal price floor and capped at the price
which will collect 100 percent of PG&E's
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total revenue requirement for the unbundled storage program for
each of the three storage subfunctions (e.g., inventory, injection,
or withdrawal).
iv. Sections IX and X of General Order No. 96-A are waived by the
Commission.
4. PG&E may also offer other customer-specific negotiated contracts.
Negotiated storage service contracts under NFS and NAS will not require
submission to the CPUC for approval; however, any other negotiated
storage service contracts will require submission to the CPUC for
approval.
5. Depending on market interest, PG&E is free to develop and offer
additional storage services in the future.
D. OTHER SERVICES
1. Parking (PARK) Services offered are identical to those approved by the
CPUC on June 26, 1996 (Advice 1949-G).
a. Definition: As-available short-term parking service, using PG&E's
transmission and storage system.
b. Term: One day to one year.
c. Rate: Negotiable, above a minimum transaction fee and capped at the
daily and/or annual cost to cycle gas using Firm Storage Service.
d. Terms and Conditions: Gas is parked and unparked at the same
location.
e. Priority: Lowest priority As-available service.
2. Lending (LEND) Services offered are identical to those approved by the
CPUC on June 26, 1996 (Advice 1949-G).
a. Definition: As-available short-term loan of gas using PG&E's
transmission and storage system.
b. Term: One day to one year.
c. Rate: Negotiable, above a minimum transaction fee and capped at the
daily and/or annual cost to cycle gas using Firm Storage Service.
d. Terms and Conditions: Gas is loaned and repaid at the same
location.
e. Priority: Lowest priority As-available service.
3. PG&E may also offer other customer-specific negotiated contracts.
Negotiated service contracts under PARK and LEND will not require
submission to the CPUC
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for approval; however, any other negotiated service contracts will
require submission to the CPUC for approval.
4. Other
Depending on market interest, PG&E is free to develop and offer various
additional services in the future.
E. GENERAL TERMS AND CONDITIONS
1. These general terms and conditions will apply to PG&E's intrastate
transmission and storage systems, and to third party storage providers
located in PG&E's service territory who have an operating agreement and
who have inter-connecting facilities with PG&E. Subscription to these
services does not, in itself, subject the subscriber to CPUC
jurisdiction.
2. With the unbundling of transmission services, the crossover ban and the
backbone credit are eliminated. The following sections in PG&E's
existing tariffs are removed along with other references and
definitions as may be applicable: Rule 21, Section H, "Scheduling
Priority at Malin, Oregon"; Rule 21, Section I, "Self Identification of
Malin, Oregon Receipts"; and Rule 22, "Backbone Credit Eligibility
Criteria."
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3. Receipt Points By Path
a. The receipt points by path are as follows:
Path Receipt Points
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Malin to On-system for the Core Malin
Malin to On-system Malin
Topock to On-system Topock, Daggett, and Kern River Station
California Production and Storage to On-system PG&E interconnections with California gas
production within PG&E's service territory,
PG&E's storage facilities, or a third
party's storage facilities located in
PG&E's service territory.
Malin to Off-system Malin
Topock to Off-system Topock, Daggett, and Kern River Station
California Production, Storage, Market Center/Hub PG&E interconnections with California gas
Services, and On-system Delivery Point Pools to production within PG&E's service territory,
Off-system PG&E's storage facilities, a third party's
storage facilities located in PG&E's
service territory, PG&E's Market Center/Hub
Services, or on-system delivery point pools.
G-XF Firm Service Malin
b. Alternate Receipt Points
Alternate receipt points are allowed only within the transmission path
contracted for by a shipper.
c. New Receipt Points
New receipt points may be requested from time to time by shippers.
4. Delivery Points
a. On-system Deliveries
On-system is defined as any point at which deliveries are made to, or
for ultimate delivery to, PG&E's distribution facilities, PG&E's
storage facilities, a third party's storage facilities located in
PG&E's service territory, or end-use or wholesale loads located in
PG&E's service territory.
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b. Off-system Deliveries
Any interconnection for delivery outside of PG&E's service territory,
including Topock, Daggett, Kern River Station, Malin, etc.
c. G-XF Firm Service
Delivery points are as specified in each shipper's FTSA (Exhibit A).
5. Initial Allocation of Firm Intrastate Transmission Capacity
a. Total intrastate capacity currently available for firm transmission
services is:
MMcf/d Mdth/d
------------------ ------------------
Malin: 1,803 1,830
Topock: 1,140 1,174
CaliGas 200 192
The Malin capacity consists of 990 MMcf/d (1,005 Mdth/d) from Line 400
and 813 MMcf/d (825 Mdth/d) from Line 401.
b. PG&E's retail core initially will be allocated the following quantities
of firm transmission capacity:
Malin to Topock to
On-system On-system California
--------- --------- ----------
Annual MMcf/d 600 150 50
Mdth/d 609 155 48
c. PG&E's retail core will also hold additional seasonal winter capacity
as follows:
Malin to Topock to
On-system On-system California
--------- --------- ----------
November and March
MMcf/d 0 150 0
Mdth/d 0 155 0
December to February
MMcf/d 0 450 0
Mdth/d 0 464 0
d. The retail core capacity reservation on the Topock to on-system path
(Line 300) and the California production path can be modified in
ensuing BCAPs to account for changes in core requirements due to
factors such as core aggregation, the termination of PG&E's California
gas contracts, and the migration of core
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customers to noncore status. These modifications will not take place
prior to 2000.
e. Capacity of up to 6.5 MMcf/d (6.6 Mdth/d) is available on the Malin to
on-system path for existing wholesale customers on behalf of their core
load.
f. New services over the Malin 517 Mdth/d) not reserved under paths will
use capacity long-term firm contracts with consisting of that portion
of existing firm Expansion Line 400 capacity (383.5 shippers. This
combined MMcf/d; 389 Mdth/d) not capacity is to be redesignated
reserved for the core, by the Commission as including wholesale, and
that non-Expansion capacity, which portion of Line 401 capacity shall
be subject to "phased-in" (509 MMcf/d; rates and shall not be subject
to the tariff or contract provisions and rights (including but not
limited to the firm Expansion shippers' "Uniform Terms of Service"
rights) that apply to the Line 401 Expansion capacity reserved under
long-term contracts.
g. PG&E will conduct an open season among all creditworthy parties to
award remaining intrastate firm transmission service for at least the
minimum term and at the full tariff rate under the AFT, AFT-Off, or SFT
service. Firm capacity will first be awarded under the AFT and AFT-Off
service. Any remaining firm capacity will then be awarded under the SFT
service.
h. If a particular path is oversubscribed in the open season, PG&E will
award available firm capacity based on PG&E's determination of the
highest economic value of each bid to PG&E's gas transmission
department, as determined by PG&E.
6. Allocation of Storage Capacity
a. The following quantities of firm storage capacity will be allocated to
PG&E's retail core customers, including core transport:
Inventory Injection Withdrawal
--------- ---------- ----------
32.Bcf 93 - 209 MMcf/d 951 - 1,228 MMcf/d
33.5 MMdth 95 - 213 Mdth/d 970 - 1,253 Mdth/d
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b. The following quantities of firm storage capacity will be allocated to
system load balancing:
Inventory Injection Withdrawal
--------- --------- -----------
2.2 Bcf 50 MMcf/d 70 MMcf/d
2.24 MMdth 51 Mdth/d 71 Mdth/d
c. The following quantities of storage capacity will be allocated to the
unbundled storage program:
Inventory Injection Withdrawal
--------- --------- ----------
4.7 Bcf 13 - 30 MMcf/d 136 - 175 MMcf/d
4.79 MMdth 13 - 30 Mdth/d 139 - 179 Mdth/d
Volumes are subject to change pursuant to operating conditions. Future
fluctuations or changes in PG&E's injection and/or withdrawal
capabilities during the Gas Accord period will be assigned or absorbed
by the unbundled storage program, except for changes in storage
capabilities required on behalf of core customers served by PG&E.
d. PG&E will conduct an open season among all creditworthy parties to
award remaining firm storage service for at least the minimum term and
at the full tariff rate for Firm Storage Service.
e. If Firm Storage Service is oversubscribed in the open season, PG&E will
award available firm storage capacity based on PG&E's determination of
the highest economic value of each bid to PG&E's gas transmission
department, as determined by PG&E.
7. Subsequent Allocation of Intrastate Transmission and Storage Capacity
a. After the open season for transmission and storage capacity, any
remaining capacity will be available for subscription under the Firm,
Negotiated Firm, or As-available services on an on-going basis.
b. Customers may request negotiated rates at less than maximum rates. PG&E
will not be required to sell capacity to any shipper at less than the
full tariff rate; however, at PG&E's sole option, capacity may be
awarded based on offers that represent the highest economic value to
PG&E, as determined by PG&E.
8. Contract Assignment
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a. Unless the shipper's contract states otherwise, all transmission and
storage contracts are assignable. Such assignments may consist of all
or part of the shipper's contract quantity and all or part of the
shipper's remaining contract term.
b. Contract assignments are subject to the following requirements:
i. Assignors must notify PG&E in advance of their assignments.
ii. The assignee must satisfy PG&E's creditworthiness requirements
described in Section II.E.9. Alternatively, the assignor may, at
its option, waive the creditworthiness requirements applicable to
the assignee, in which case the assignor shall be secondarily
liable for non-performance by the assignee. If an assignor
exercises this option, it must demonstrate to PG&E's satisfaction
that it remains creditworthy itself.
c. To encourage assignments and development of an active secondary market,
PG&E will maintain a posting board similar to PG&E's existing "Energy
Marketplace" that contract holders may use, at their option. PG&E is
willing to work with others to establish new or modify existing
mechanisms, including electronic bulletin boards, that encourage
development of an active secondary market.
9. Creditworthiness
a. An entity requesting service must demonstrate creditworthiness before
receiving service. Additionally, an entity receiving service under a
long-term (one year or longer) contract may be subject to periodic re-
evaluations of its creditworthiness.
b. An entity requesting service must provide the following to PG&E in
order for PG&E to evaluate its creditworthiness:
i. Most recent annual report;
ii. Most recent SEC Form 10-K;
iii. If SEC Form 10-K is unavailable, substitute audited annual
financial statements (including a balance sheet, income statement,
and cash flow statement), o r
iv. If audited financial statements are unavailable, substitute
unaudited financial statements (including a balance sheet, income
statement, and cash flow statement) accompanied by an attestation
by the providing entity's Chief Financial Officer that the
information reflected in the unaudited statements is true and
correct and a fair representation of the entity's financial
condition;
-20-
v. Most recent quarterly or monthly financial statements (including a
balance sheet, income statement, cash flow statement, and
contingencies).
c. PG&E will use the items above, in conjunction with the entity's service
request or service level, to determine the maximum amount of credit
PG&E can offer the entity.
d. If an entity is unable to demonstrate creditworthiness through the
materials listed in Section b, PG&E may request additional evidence of
creditworthiness, in which event the entity may elect to provide one of
the following:
i. an irrevocable letter of credit in form, substance and amount
satisfactory to PG&E;
ii. a guarantee, in form and substance satisfactory to PG&E, executed
by a person PG&E deems to be creditworthy, of the entity's
performance of its obligations to PG&E; or
iii.such other form of security as the entity may agree to provide and
as may be acceptable to PG&E.
e. PG&E will treat all financial statements provided to it as
confidential.
f. PG&E will continue to oversee aggregators' creditworthiness, pursuant
to PG&E's Gas Rule 23 - Gas Aggregation Service for Core Transport
Customers.
10. Priority of Service
a. The current Receipt Point Capacity Allocation rules will change to
reflect the following priorities.
b. Scheduling Priority at Transmission Receipt Points (in the following
order)
i. Firm Intrastate Transmission: All firm service at all receipt
points on a defined transmission path is treated equally (pro rata
allocation of nominations if necessary).
ii. As-available Intrastate Transmission: Scheduled according to
contract price.
c. Scheduling Priority at Transmission Delivery Points (in the following
order):
i. Firm Intrastate Transmission: All firm service at a given delivery
point is treated equally (pro rata allocation of nominations if
necessary).
ii. As-available Intrastate Transmission: Scheduled according to
contract price.
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d. Scheduling Priority To Storage for Injection
i. Transportation priority to storage is determined by the underlying
intrastate transmission contract.
ii. Injection priority at PG&E's storage interconnection is determined
by the storage contract:
* PG&E Firm Storage Service: All firm service treated equally (pro
rata allocation of nominations if necessary).
* PG&E As-available Storage Service: Scheduled according to
contract price.
e. Scheduling Priority From Storage for Withdrawal
i. Transportation priority from storage to the delivery point is
determined by the underlying intrastate transportation contract.
ii. Withdrawal priority at PG&E's storage interconnection is determined
by the storage contract.
* PG&E Firm Storage Service: All firm service treated equally (pro
rata allocation of nominations if necessary).
* PG&E As-available Storage Service: Scheduled according to
contract price.
f. Over-Nomination Provision
PG&E will develop a tariff provision to discourage nominations in
excess of actual available supply (over-nomination) at a constrained
receipt or delivery point.
11. Local Constraints
a. PG&E will take whatever steps it determines are operationally necessary
in the event a constraint on local transmission or distribution
threatens service to customers. This includes curtailment of noncore
customers.
b. To the extent feasible, PG&E will use the transmission system diversion
procedures to prioritize noncore customers in the affected service
area.
c. In the event of an Emergency Flow Order (EFO) due to a local
constraint, EFO penalties may apply, but involuntary diversion
penalties will not apply.
12. Service Reliability and Diversion Procedures
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a. When operational conditions exist such that supply is insufficient to
meet demand and delivery to end-users is threatened, the diversion of
supply may be used to ensure continued gas delivery to core end-users.
EFO provisions will apply under these conditions (see Section II.E.13).
If a noncore end-user's supply is diverted, either voluntarily or
involuntarily, then that end-user must curtail its use of natural gas.
If a core end-user's supply is diverted, then that customer must pay
any penalties if it continues to use gas, as referenced later in this
Section.
b. The following diversion procedures will apply to ensure service
reliability to core end-users. PG&E's core procurement department and
core aggregators, on behalf of core customers, will use:
i. their own firm capacity, to the extent possible;
ii. any available As-available capacity on the system at any receipt
point; and
iii.available voluntary diversion of supply from noncore end-users or
other transmission system shippers, at prices not to exceed the
cost of involuntary diversion.
c. Involuntary diversion of gas supply on the transmission system will be
used as a last resort to ensure service reliability for core end-users.
Firm transportation to off-system is not subject to diversion.
Diversion will occur in the following order:
i. Noncore supply scheduled under As-available transportation is
diverted in order of contract transmission price and on a pro rata
basis for all volumes with the same price. However, scheduled
deliveries from storage using As-available transmission will be
treated as the highest priority noncore firm transmission.
ii. Firm transportation to on-system noncore end-users.
d. Those receiving involuntarily diverted supply will be assessed a
$50/Dth diversion usage charge in addition to a $50/Dth EFO curtailment
noncompliance penalty, for a total noncompliance charge of $100/Dth.
These revenues will be used first to pay diversion credits to those
whose gas supply is involuntarily diverted. The remaining revenues will
be returned to all customers in the customer class charge.
e. Firm transportation service customers whose gas supply is involuntarily
diverted will receive a $50/Dth diversion credit.
f. As-available transmission service customers whose gas supply is
involuntarily diverted will receive a diversion credit based on the
current market price of the diverted supply.
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13. Balancing Service
a. Basic Service
i. Balancing service will be provided on a monthly basis through a
single integrated gas system for both transmission-level and
distribution-level customers.
ii. All customers shall exercise best efforts to have daily gas
receipts match daily gas usage.
iii.Monthly imbalances can be carried forward one month, not to exceed
plus or minus five percent of the usage in the month in which the
imbalance occurred, except as noted in items a.iv and d, below.
iv. If at any time the aggregate imbalance on PG&E's system (excluding
the operation of the storage reserved for balancing) has exceeded
plus or minus three percent of that month's aggregate deliveries
(excluding gas scheduled for subsequent delivery off-system) for
two months in the preceding 12 month period, then the imbalance
carry-over allowance will be decreased one percent after a minimum
of 30 days notice to the market. This provision can be used to
lower the imbalance carry-over allowance no more than once in any
12 month period. The carry-over allowance will not be set below
three percent without CPUC approval. All references in the Gas
Accord to a five percent carry-over allowance and to the tiers for
monthly imbalance cash-outs are intended and understood to be
subject to change by operation of this provision.
v. Operational Flow Order (OFO) and Emergency Flow Order (EFO)
provisions will be used to manage operational imbalances when
necessary.
b. Customer Imbalances
i. Imbalances generally will be maintained at the delivery point. For
deliveries made to on-system end-users, the end-user will be
responsible for imbalances. For deliveries to storage and to off-
system points, the transmission shipper will be responsible for
imbalances.
ii. End-user imbalance accounts may be assigned to a third party.
iii.A third party may aggregate imbalance accounts.
c. Imbalance Trading
i. Monthly imbalance quantities may be traded with another entity.
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ii. Imbalance quantities can only be traded with other imbalance
quantities that occurred during the same calendar month. Trading
between on- and off-system imbalances is not allowed.
iii.Any imbalance trade must move the trader's imbalance quantity
toward zero, unless the imbalance resulting from the trade is
within the range of plus or minus three percent.
iv. Imbalance trading into and out of storage will be available. Firm
storage customers may use a PG&E (or other on-system storage
provider's storage account subject to having an appropriate
operational balancing agreement between PG&E and the other storage
provider) to trade transportation imbalances, during the imbalance
trading period, within operational limits.
d. Imbalance Charges and Cash-Out
i. Automatic cash-out of all commodity and transmission imbalances
outside of allowed carry-forward quantity each month will occur.
In-kind imbalance deliveries will not be included. Imbalance cash
-outs will have a commodity and a transmission component. Monthly
imbalance cash-out occurs after imbalance trading for the month is
complete.
ii. Commodity cash-out prices for each month for each interconnect are
based on the higher (for under-deliveries) or lower (for over-
deliveries) of the following gas price indexes at PG&E
interconnects (e.g. Malin, Topock) from public sources (e.g.
Bloomberg, Gas Daily):
* Monthly index price;
* Under-deliveries: average of the five highest daily index prices
during the month;
* Over-deliveries: average of the five lowest daily index prices
during the month.
iii.The commodity cash-out index price for imbalances less than or
equal to ten percent will weight the appropriate interconnect
indices by the supply mix of all gas received by PG&E for on-system
customers during the month in which the imbalance occurred.
Imbalances greater than ten percent will be cashed-out based upon
an index equal to the highest interconnect index price for under-
deliveries and the lowest interconnect index price for over-
deliveries, regardless of PG&E's supply mix.
iv. The commodity cash-out index price will be adjusted by the
following percentages, according to the level of the actual monthly
imbalance:
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Monthly Imbalance Over-delivery (OD) Under-delivery (UD)
Level Purchase Dollars Sale Dollars
- ----- ---------------- ------------
+/-5% to +/-10% 95% weighted OD index 105% weighted UD index
>+/-10% 50% lowest index 150% highest index
v. Transmission service cash-out prices are based on the volumetric
component of PG&E's standard tariff firm (MFV) and As-available
transmission services. Over-deliveries will receive a transmission
service credit based on the volumetric component of the appropriate
firm transportation rate. Under-deliveries will be charged the
appropriate rate for As-available service. The appropriate rate is
determined by weighting the path specific rates by the supply mix
of all gas received by PG&E for on-system customers during the
month.
vi. PG&E gas purchases and/or sales associated with cash-outs will be
accounted for separately from the core portfolio purchases.
vii.The intent of imbalance cash-outs is to create an economic
disincentive for incurring cash-out imbalances. PG&E will file to
revise the imbalance charges and cash-out options if the Gas Accord
provisions do not accomplish this.
e. Operational Flow Order Provisions
i. System-wide, local, or customer-specific OFO provisions may be
called to order out-of-tolerance customers to balance supply and
demand daily, when operationally necessary. OFO provisions will
require daily balancing and impose penalties for noncompliance.
ii. OFOs may be called if pipeline inventory exceeds or is forecast to
exceed desired pipeline inventory by 200 MMcf/d, or is below or is
forecast to be below desired pipeline inventory by 150 MMcf/d.
Desired pipeline inventory in the winter is typically 4.2 Bcf and
in the summer is typically 4.15 Bcf.
iii.PG&E will use multi-stage OFO provisions, which would provide a
daily tolerance band ranging from plus or minus 25 percent to zero
percent of actual daily usage.
iv. Multi-stage OFO non-compliance penalty provisions would range from
$1/Dth to $25/Dth. The amount of the penalty will be announced
prior to the enactment of each stage. The penalty will start at
$1/Dth and only increase during an event if the response to the OFO
is inadequate. Subsequent levels will be $5/Dth and $25/Dth, as
needed to maintain pipeline system integrity. A specific customer
may start at an elevated penalty level if that customer has a
history of non-compliance.
-26-
v. An OFO will normally be ordered with at least twelve hours notice
prior to the beginning of the gas day, or as necessary as dictated
by operating conditions. Penalties will not be imposed with less
than twelve hours notice.
vi. For each noncore end-user without telemetering, compliance with an
OFO will be determined by comparing the end-user's supply against a
5:00 p.m. day-before PG&E forecast of the end-user's usage.
f. Emergency Flow Order Provisions
i. Emergency Flow Order conditions are defined to exist when a
forecast or actual supply and/or capacity shortage threatens to
affect the delivery to end-users.
ii. EFOs will have a zero percent tolerance (supply must be greater
than or equal to usage) and a $50/Dth noncompliance penalty.
iii.For each noncore end-user without telemetering, compliance with an
EFO will be determined by comparing the end-user's supply against a
5:00 p.m. day-before PG&E forecast of the end-user's usage.
iv. If an involuntary supply diversion is called in conjunction with an
EFO, an additional $50/Dth diversion usage charge will apply for a
total potential noncompliance penalty of $100/Dth.
v. An EFO would normally be ordered following an OFO, but could also
occur under an emergency operational condition. There is no
required notice period for EFOs, however, PG&E will attempt to
provide as much notification to customers as possible.
vi. PG&E reserves the right to implement other measures to ensure
system integrity should the EFO actions not alleviate the emergency
condition.
g. Other Operational Balancing Issues
i. Transmission-level end-users and distribution-level noncore end-
users will be required to have daily metering.
ii. Telemetering will be installed on noncore customers' meters where
it is cost-effective. These costs will not change the rates
established by the Gas Accord.
iii.PG&E reserves the right to propose other measures to ensure system
integrity should the OFO and/or EFO provisions not prove to be
adequate.
iv. A load profile modeling tool will be developed to determine daily
usage for PG&E's core procurement customers and core transport
customers served by
-27-
core aggregators in order to remove PG&E's core portfolio from
providing a system balancing function, and to be able to hold
PG&E's core procurement department to the same balancing and OFO
provisions to which others are held.
v. The normal nomination deadline will be shifted to one day prior to
gas flow at all receipt points where the upstream operator(s) will
accommodate the shift.
vi. PG&E will allow same-day nominations, if necessary, and if upstream
and downstream operator(s) are able to accommodate the practice.
14. Transmission Level End-Use Service
a. To be eligible for transmission-level end-use service, an end-user
must:
i. Be a noncore customer;
ii. Be physically connected to the transmission system or have an
annual load in excess of 3 million therms/year; and
iii.Elect to receive transmission level end-use service.
b. All on-system transmission-level end-users must pay local transmission
charges.
c. All other end-users will be served at distribution tariff rates.
d. The definition of a noncore customer may be revisited in BCAPs during
the Accord period.
15. Negotiated Contracts
a. Standard tariff rates and terms are available to all customers.
b. PG&E may distinguish between parties in offering negotiated rates by
evaluating differences in circumstances and conditions, including but
not limited to differences occurring upstream, downstream or at the
customer's location, affecting either cost of service or the entities'
market alternatives. Such negotiations will be conducted without undue
preference or undue discrimination.
c. Negotiated rates for transmission and storage service shall not be less
than PG&E's short-run marginal cost of providing the service.
Negotiated transmission rates under NFT and NAA will be capped at 120
percent of the tariffed rate for the particular service on the
particular path. Negotiated storage rates (NFS and NAS) will be capped
at the price which will provide PG&E the opportunity to recover its
total embedded cost revenue requirement for the unbundled storage
program for each of the three storage subfunctions (e.g., inventory,
injection, or withdrawal).
-28-
d. To the extent that PG&E negotiates a transmission contract for its
Malin to on-system path with an on-system end-user, and the negotiated
backbone rate component offered is below the analogous Topock to on-
system path rate, e.g., seasonal firm, PG&E agrees to offer to that
end-user the same negotiated rate for a Topock to on-system path
contract, to the extent that capacity is available .
e. Negotiated rates for parking and lending services shall not be less
than PG&E's short-run marginal cost of providing the service. These
rates will be capped at a daily and/or annual cost to cycle gas using
firm storage service.
f. PG&E will issue monthly reports to CPUC covering all negotiated
contracts, including those negotiated under NFT, NAA, NFS, and NAS, but
excluding PARK and LEND. PG&E will make the report available upon
request. Customer names, including PG&E's affiliates and other
departments, will not be disclosed in the report. However, the report
will indicate whether a particular transaction was with an affiliate.
The report will show the negotiated contract rates.
g. The CPUC's complaint procedure will be available to address any undue
discrimination claims.
h. PG&E may also offer other customer-specific negotiated contracts.
Negotiated transmission and storage service contracts under NFT, NAA,
NFS, and NAS will not require submission to the CPUC for approval;
however, any other negotiated transmission or storage service contracts
will require submission to the CPUC for approval.
16. Affiliate and Intracompany Transactions
a. PG&E will treat PG&E's affiliates and core procurement and UEG
departments without undue preference or undue discrimination.
b. PG&E will not disclose specific shipper information to PG&E's
affiliates or core procurement and UEG departments without that
shipper's permission, except as needed to serve the shipper.
c. PG&E will provide nonpublic information about the intrastate
transmission system to all entities, including PG&E's affiliates and
core procurement and UEG departments, without undue preference or undue
discrimination.
d. PG&E will develop specific standards of conduct for affiliate
transactions to be included in its Accord tariffs.
F. SPECIAL AGREEMENTS
1. Firm Expansion Agreements
-29-
a. As set forth in Section I.B.6, the 304 MMcf/d of Line 401 capacity
remains initially dedicated to firm G-XF service, consistent with the
Firm Transportation Service Agreements (FTSAs) previously approved by
the CPUC for service to the firm Expansion shippers. The G-XF rate will
continue to apply to this capacity and to service provided to these
shippers for the remainder of the 30-year term of these agreements, as
set forth in part (b.ii), below, except that each shipper may elect one
of the options set forth in parts (b.i) and (c), below, and, by virtue
of that election, alter the rate, term, and terms and conditions of
service. The other 509 MMcf/d of Line 401 firm capacity is redesignated
as firm capacity available for subscription under the new transmission
services described in Section II.A.
b. Options for Service: Firm Expansion shippers may elect
--------------------
one of the following options for restructuring their contractual
commitments. The shippers may elect either of the following two options
at any time up to 45 calendar days following CPUC approval of this
Settlement Agreement.
i. Accord Service: A shipper may convert its firm Expansion
---------------
contract to Firm Annual Off-System service (AFT-Off) under the
Accord for Malin to off-system service. The rate, terms and
conditions of this service are delineated in Section II.A.4. These
include a Line 401 capital cost of $736 million, and an on-system
delivery option if the shipper elects SFV rate design. Features
specially applicable to converting Expansion shippers are the
following:
* the term of the replacement contract is the full
remainder of the shipper's 30-year term under its FTSA;
* UTS and all other Expansion-related contract and tariff
rights must be irrevocably waived;
* the contract for new service is pro forma (no negotiated
agreements) and service is henceforth provided under AFT-Off and
superseding tariff(s);
* the shipper's capacity is redesignated as non-Expansion
capacity, as discussed in Section I.B.6; and
* PG&E will offer consideration as payment for the
shipper's waiver of UTS rights.
ii. G-XF Firm Service: Those firm Expansion shippers that do
------------------
not elect one of the other options set forth herein will continue
to receive service under G-XF, as described below:
* Rates are based on a $736 million capital cost, using PG&E's
proposed cost of capital and utility capital structure;
* Rates remain incremental and are based on the operating expenses
and cost allocation methodologies proposed by PG&E in its PEPR
Application;
* The G-XF firm service continues to apply, but is modified to
reflect the revenue requirement assumptions above, and the
backbone credit and crossover ban are eliminated;
-30-
* UTS and all other contract rights remain applicable only to firm
G-XF service; and
* Delivery points are as set forth in Exhibit A to each shipper's
FTSA.
c. Other Options: PG&E is also offering the following three options to
-------------
firm Expansion shippers. The following descriptions set forth PG&E's
vision of these options, but each option will be negotiated with any
interested shipper, and specific terms and conditions may vary as a
result of those negotiations. The shippers may elect one of these
options by executing the appropriate agreement with PG&E on or before
the earlier of (1) December 1, 1996, or (2) the date the CPUC approves
this Accord Settlement Agreement.
i. Negotiated Contract Amendments: A shipper may elect either a
------------------------------
discounted rate (to be negotiated with PG&E), which is fixed for
the term of the Gas Accord, or a market index rate, which would
fluctuate during the term of the Gas Accord within a negotiated
floor and ceiling based on differentials between Southwest and
Canadian prices. Service under either rate option, once agreed to,
will be provided under G-XF, as modified by the Gas Accord. At the
end of the Gas Accord term, and for the remainder of the shipper's
30-year contract term, rates will be set based on a Line 401
capital cost of $736 million. Beginning on the date the contract
amendment is executed, the shipper must waive its UTS provision
for the remainder of its 30-year contract term.
ii. Contract buyout: A shipper may terminate its contract
---------------
obligations either by making a single payment to PG&E or
accelerating payment of demand charges by means of a higher
negotiated rate for a specified negotiated term. In either case,
PG&E intends that the payment shall be of a sum less than the full
NPV of the remainder of the shipper's 30-year contract term. Upon
payment of the full negotiated buyout amount, the shipper's
contract with PG&E for Expansion transportation service, and all
rights and obligations under that contract, shall terminate, and
the capacity released thereby shall be redesignated as non-
Expansion capacity and shall become part of the pool of capacity
used to provide Accord transmission services. If a shipper elects
the accelerated payment option, service for the term of such
payment will be provided under G-XF, as modified by the Gas
Accord, and the shipper must waive its UTS provision immediately.
iii. Equity Purchase: A shipper may convert its firm service to an
---------------
equity interest in Line 401 at a purchase price to be negotiated
with PG&E. Under this option, the shipper would purchase a share
of Line 401 at least equal to the firm Maximum Daily Quantity
(MDQ) set forth in Exhibit A to the shipper's FTSA.
2. EAD Contracts
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The EAD contracts provide the equivalent of contract rights as firm
transportation service (AFT) on the Topock to on-system path, but at the
contract volumetric rate. The EAD customers will have the option of
continuing to receive the same bundled transportation service, or taking
service under a Gas Accord contract. Service under Gas Accord contracts will
contribute to any use-or-pay obligations under the EAD contract. Because of
the unique terms and conditions in the various EAD contracts, individual
discussions are needed as to how specific contract provisions will be
implemented in the Gas Accord contract environment.
3. EOR Contracts
In Decisions 85-12-102 and 87-05-046, the Commission established a long-term
transportation program and set the criteria for Enhanced Oil Recovery (EOR)
contracts. Existing EOR contracts will be treated based on the Commission's
decisions during the Accord period, or until the expiration date of such
contracts, whichever is earlier. Future EOR service will be provided based
on the terms and conditions of Accord services.
4. EDCD Agreements
In Decision 94-12-061, the Commission established the Expedited Direct
Connection Docket (EDCD) for case-by-case approval of direct connection
service on PG&E's Line 401. PG&E has one EDCD application (A.96-04-007)
pending before the Commission and may file additional applications. To the
extent these applications are approved before the Gas Accord is implemented,
the underlying agreements shall continue in effect during the Gas Accord
until they expire. Otherwise, new services are provided consistent with the
Accord services.
5. Other Existing Agreements
a. Negotiated Interruptible Agreements
PG&E has a number of negotiable interruptible transportation agreements
with terms that may extend into the Accord period. PG&E will continue to
honor the terms and conditions, including the rate, negotiated for the
original term of these contracts. Because the underlying tariff (G-ITS)
will be eliminated upon Accord implementation, these terms and
conditions will be carried out through an NAA contract.
b. Crockett Cogeneration
-32-
Crockett cogeneration has a negotiated contract which provides for
transportation service at volumetric rates. PG&E will continue to honor
the terms and conditions, including the rate, negotiated for the
original term of this contract. If any terms and conditions are
unspecified by the existing contract agreement, then the applicable Gas
Accord tariffs will apply.
6. SMUD
a. Background
Sacramento Municipal Utility District (SMUD), as the largest municipal
utility in the state, is in a unique position and the Accord proposes a
unique solution to meet its needs. PG&E and SMUD have agreed, subject to
completing definitive agreements and obtaining CPUC approval, that PG&E
will sell to SMUD a qualified equity interest in Line 300 and Line 401
backbone facilities.
This transaction along with the Interim and Contingent Rate discussed
below, would settle SMUD's BCAP Phase II issues. The details of the
transaction will be part of a Section 851 filing seeking CPUC approval
of the asset sale.
b. Interim and Contingent Rate
Should the above asset transfers not occur before the Gas Accord becomes
effective, there will be an interim rate, which is also a contingent
rate in the event that the Section 851 filing is not approved as filed.
This rate will include a $0.123 per Dth discount (escalated for
inflation over time) from the local transmission charge component of the
otherwise applicable tariff rates for gas delivered and received by SMUD
or its affiliate to support its electric utility operations. This rate
treatment will terminate upon closing of SMUD's purchase of a qualified,
equity interest in Lines 300 and 401.
G. GENERAL DESCRIPTION OF TRANSMISSION AND UNBUNDLED STORAGE PROGRAM RATES
1. Unbundle transmission and a portion of storage from distribution services.
2. Establish transmission, distribution, and storage rates based on cost of
service.
3. Make transmission and storage service available to all entities,
including end-users, shippers, producers and marketers.
4. Collect social, environmental, and transition costs and balancing
accounts from on-system end-use volumes.
5. Backbone rates associated with service to storage are paid upon
injection. For on-system deliveries, the remaining transmission rates
are paid upon withdrawal.
6. New Transmission Rates
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a. Differentiate transmission rates by path to reflect facilities used
to provide service.
b. Establish two-part firm rates (reservation and usage charges) and
one-part As-available rates (volumetric or usage charges).
c. Establish a customer access charge to cover the costs of meters and
service drops, meter reading, billing and payment processing where
applicable.
7. Pre-existing Transmission Rates
For those services with pre-existing contracts discussed in Section II.F,
charge the rates shown in Section II.B.
8. Storage Rates for the Unbundled Storage Program
a. Establish two-part (reservation and volumetric) rates for both the
capacity (injection and inventory) and withdrawal subfunctions for
Firm Storage Service.
b. Negotiated storage rates may be based on three subfunctions
(inventory, injection, and withdrawal) and may be either one-part or
two-part rates.
H. TRANSMISSION AND UNBUNDLED STORAGE PROGRAM RATES
1. New Transmission Rates
a. Four rate components will be applicable to on-system transmission
service. A backbone transmission charge, a local transmission
charge, a customer class charge, and a customer access charge.
Shippers delivering on-system will be charged the backbone
transmission charge, and corresponding end-users will be charged the
local transmission charge, the customer class charge and customer
access charge.
b. The backbone transmission charge, the local transmission charge, and
the transmission-level customer access charge, will not change from
the rate set forth in this Accord, except pursuant to the z-factor.
c. New off-system transmission service under the Accord includes a
backbone transmission charge, and a customer access charge where
applicable. The backbone transmission and customer access charges
are guaranteed except for the z-factor.
d. Backbone Transmission Charge
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i. The backbone transmission charge is designed to collect backbone
transmission revenues and is applicable to all transmission
customers.
ii. The retail core market receives 600 MMcf/d (609 Mdth/d) and the
core wholesale market receives up to 6.5 MMcf/d (6.6 Mdth/d) of
Malin to on-system firm intrastate capacity at vintaged rates.
iii. The Malin to on-system rate is based on an intrastate capacity
phase-in, over the period from 1997 through 2002 of 375 MMcf/d
(381 Mdth/d) of Line 401 and the portion of Line 400 embedded
costs not allocated to the retail core and core wholesale.
e. The local transmission charge collects local transmission costs and
is applicable to all on-system end-users.
f. The customer class charge includes social, environmental and
transition costs, balancing account balances and all other non-base
revenue requirements. Some of the costs included in this charge are
CARE, CEE programs, hazardous substance, and ITCS costs. It is
generally applicable to all on-system end-users.
g. The customer access charge includes the cost of meters and service
drops, meter reading, billing and payment processing, and is
applicable to the customers to whom PG&E provides these services
(see Section II.I.10).
h. Transmission rates for AFT, SFT, and AA are shown in Section VI.
2. Pre-existing Transmission Rates
Pre-existing services and contracts are discussed in Sections II.B and
II.F.
3. Storage Rates for the Unbundled Storage Program
a. Rates for storage services are based on the costs of storage
injection, inventory and withdrawal.
b. Firm Storage
i. Rates are subfunctionalized by a capacity (combined injection and
inventory) charge and withdrawal charge.
ii. Capacity and withdrawal charges are recovered through a
reservation (fixed) and volumetric (variable) component.
c. Negotiated Firm and As-available services are negotiable above a
price floor representing PG&E's short-run marginal cost of providing
the service.
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d. Negotiated Firm rates can be recovered through a volumetric-only
charge or a reservation and volumetric charge.
e. Negotiated As-available Storage Injection and Withdrawal rates are
recovered through a volumetric charge only.
f. Negotiated storage rates (NFS and NAS) are capped at the price which
will collect 100 percent of PG&E's total embedded cost revenue
requirement for the unbundled storage program for each of the three
storage subfunctions (e.g., inventory, injection, or withdrawal).
The flexibility inherent in this storage offer could result in
stranded facilities and PG&E requires the opportunity to collect the
value of its storage services.
g. Firm storage rates for the unbundled storage program are shown in
Section VI.
I. COST BASIS AND RATE DESIGN
1. The Backbone Component of New Transmission Path Rates
a. Except for certain services and contracts described in Section II.F,
all on-system rates include a backbone transmission component that
varies by path, and a common backbone component. The common backbone
component includes the costs of backbone facilities used by all on-
system paths, and gathering mains.
b. The incremental Line 401 costs used in developing the Malin to on-
and off-system rates are based on the Pipeline Expansion assumptions
shown in Section II.I.3. Off-system rates do not include any common
backbone component.
c. Malin to on-system rates for the core (including core wholesale) are
based on a prorated portion of vintaged Line 400 and Line 2, and the
common backbone component.
d. Malin to on-system rates for all customers except retail core and
core wholesale include the cost of the portions of Line 400 and Line
2 not reserved for the core, the common backbone component, and a
phased-in portion of Line 401 costs as described in Section II.I.3.
e. Both the Topock to on-system and the Topock to off-system rates
include the cost of Line 300 and the common backbone component.
Capital costs of $42 million for NOx-related retrofits needed to
meet NOx emission standards are included in the Line 300 revenue
requirement. To the extent PG&E's expenditures exceed the $42
million, PG&E will be at risk for recovery of these expenditures
during the Gas Accord period, but does not waive the right to seek
recovery after that.
f. California production to on-system rates include 40 percent of the
average backbone transmission costs and the common backbone
component. California
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production to off-system rates assume Line 401 will be used, and the
rate is equal to the Line 401 to off-system rate.
g. The on-system and off-system rates are guaranteed for the Accord
period, subject to change pursuant only to the z-factor provision of
Section II.I.7.
2. The Storage Costs in the Unbundled Storage Program
a. The storage costs allocated to the unbundled storage program
represent 12.5 percent of the inventory, injection, and withdrawal
storage costs remaining after the allocation for load balancing
requirements.
b. The maximum rates for Negotiated Firm Storage and Negotiated As-
available Storage are based on a rate design assuming an average
injection period of 30 days and an average withdrawal period of
seven days. The rates assume full collection of the total unbundled
storage program revenue requirement in each individual subfunction.
c. The minimum rates for Negotiated Firm Storage and Negotiated
As-available Storage are based on the marginal price floor to provide
the service.
3. Revenue Requirement Assumptions
a. Gas Department (excluding Pipeline Expansion)
i. Initial base revenue requirements for calculating 1997 rates
match PG&E's 1996 GRC.
ii. Cost of capital and capital structure are based on the 1996 Cost
of Capital proceeding's authorized cost of capital for the gas
department.
iii. Gas department common costs are allocated to backbone
transmission, local transmission and distribution based on plant
and labor.
b. Development of the Line 401 Revenue Requirement
i. Base revenue requirements are calculated using the proposed
litigation resolution figure of $736 million of capital costs
discussed in Section V. Operating expenses and the methods used
to allocate costs and calculate taxes and the revenue
requirement match PG&E's current position in the Pipeline
Expansion Project Reasonableness (PEPR) Case.
ii. Cost of capital and capital structure matches PG&E's gas
department cost of capital as authorized in the 1996 Cost of
Capital Decision 95-11-062, with no premium on the return on
equity.
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iii. No common costs, except those included in the PEPR Case, are
included. The cost allocation methods match those used in the
PEPR Case. The allocation of original facilities to the
Expansion increases to the amount proposed by PG&E in the PEPR
Case.
c. Line 401 Cost Phase-in to On-system Rates
Each year a portion of the Line 401 revenue requirement will be
included in the Malin to on-system rate. The portion is calculated
using the firm Expansion capacity of 813 MMcf/d (825 Mdth/d). The
Line 401 revenue requirement phased-in each year will be based on
depreciated plant. The following table summarizes the amount of
capacity used to determine the phased-in costs:
Capacity 1997 1998 1999 2000 2001 2002
---- ---- ---- ---- ---- ----
Incremental 200 50 50 25 25 25
(MMcf/d)
Cumulative 200 250 300 325 350 375
(MMcf/d)
Cumulative 208 254 305 330 355 381
(Mdth/d)
4. Load Factor and Rate Cap Assumptions
a. Firm annual on-system backbone transmission charges are based on an
annual average capacity factor of 87.5 percent. Malin to on-system
capacity increases each year consistent with the cost phase-in.
Seasonal firm and As-available rates are set at 120 percent of the
annual firm rates. As-available rates are set at 110 percent of the
annual firm rates through March 31, 1998, and at 120 percent
thereafter. The load factors used in setting backbone transmission
rates remain constant through the Gas Accord period. The core's Topock
to On-system path charge for firm seasonal capacity will be calculated
at 110 percent of the firm annual price for the period through March
1998.
b. The Malin to off-system firm rates are calculated using incremental
Line 401 costs and a 95 percent load factor. The Malin to off-system
As-available rates are set at 110 percent of firm rates through March
31, 1998, and at 120 percent thereafter.
c. On-system California production and storage to off-system rates are
equal to the Malin to off-system rates.
5. Balancing Account Treatment
a. There will be no balancing account treatment for backbone or local
transmission revenues, or for parking or lending service revenues.
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b. The current storage program has a contractual operating period from
April 1 through March 31. Therefore, PG&E will not offer firm storage
service until April 1, 1998, and PG&E will continue to honor storage
contracts for the 1997/1998 storage season. PG&E may begin offering
as-available storage service upon implementation of all other
services if capacity is available. Balancing account treatment for
the current storage program will continue through March 31, 1998.
Any outstanding balance plus interest will be allocated to core and
noncore customers on an equal cents per therm basis. PG&E will
absorb 100 percent of the core share.
6. Shrinkage (compressor fuel, and lost and unaccounted for gas)
In-kind shrinkage will be charged to all gas shipped on the PG&E
transmission system on a postage-stamp basis. Additional shrinkage will be
charged for distribution service, also on a postage-stamp basis. The Malin
to off-system shrinkage rate is the rate adopted in Decision 94-02-042.
The shrinkage rate for all other transmission paths is developed using
rates authorized in PG&E's BCAP Decision 95-12-053 and is subject to
change in subsequent BCAPs. Transmission shrinkage will be charged for all
deliveries into storage, but not for deliveries out of storage.
Path Shrinkage Rate
---- --------------
Malin to Off-system 1.11%
All Other Transmission Paths 1.72%
7. Rate Adjustments
a. The Line 400 component of Malin rates escalates at 2.5 percent
annually.
b. Line 401 costs used to establish the phase-in component of the Malin
to on-system rates and the Malin to off-system rates are adjusted in
accordance with PG&E's Pipeline Expansion Rate Case methodology and
the litigation resolution agreement in Section V.
c. Line 300 rates escalate at 2.5 percent annually, plus the revenue
requirement associated with the $42 million of capital cost additions
for NOx-related retrofits needed to meet NOx emission standards.
d. Storage and parking and lending rates escalate at 2.5 percent
annually.
e. The guaranteed rates may be adjusted by a z-factor to reflect
extraordinary costs or savings. The z-factor is limited to known
changes due to governmental action. An example of a government action
would include changes to the federal or state income tax rate. The z-
factor mechanism would not replace either the current CEMA or the
Hazardous Substance incentive mechanism, both of which would remain in
effect.
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f. The following z-factor sharing mechanism (costs or savings) is
adopted for cost responsibility per each extraordinary event:
z-Factor Cost (Savings) Cost
Per Event Responsibility
----------------------- --------------
$0 - $5 million 100% PG&E
(greater than) $5 - $10 million 50/50 sharing
(greater than) $10 million 100% customers
8. Local Transmission Charge
a. The charge includes the cost of local transmission facilities.
b. The local transmission charge is paid by all on-system end-users.
This charge is non-bypassable.
c. The local transmission charge varies by core and noncore customer
class. Local transmission costs are allocated to core and noncore
based on LRMC methodology from PG&E's BCAP Decision 95-12-053.
d. Local transmission rates escalate at 2.5 percent annually.
e. The local transmission charge will have no balancing account
protection.
f. The rates are guaranteed for the Accord period, subject only to the
z-factor provisions of Section II.I.7.
g. Local transmission rates are shown in Section VI.
9. Customer Class Charge
a. The customer class charge is designed to collect social, environmental
and transition costs, balancing account balances, and all other non-
base revenue requirements. Some of the costs included in this charge
are CARE, CEE programs, hazardous substance, and ITCS costs.
b. The core customer class charge does not include ITCS. PG&E will absorb
all of the core portion of the ITCS charges as defined herein, less
brokering revenues, plus interest, from the beginning of the ITCS
account, as part of the litigation resolution described in Section V.
The customer class charge includes a "true-up" of ITCS costs collected
from core customers prior to Accord implementation.
c. The noncore customer class charge includes only 50 percent of the
noncore ITCS costs, less brokering revenues, plus interest, from the
beginning of the ITCS account. PG&E will absorb the remaining 50
percent of the noncore ITCS costs, as part of the litigation
resolution described in Section V.
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d. The customer class charge does not include any component for recovery
of the backbone credit. PG&E will absorb 100 percent of the Backbone
Credit Account. PG&E will not provide any shipper with a backbone
credit after the Gas Accord is approved, as part of the litigation
resolution described in Section V.
e. Initial customer class charges have been allocated to customer classes
and will be collected in rates as determined in PG&E's 1996 GRC and
PG&E's BCAP Decision 95-12-053. These charges will be periodically
adjusted based on the regulatory proceedings associated with each
account and continue to be subject to balancing account treatment.
f. PG&E will collect the existing balance in the Noncore Fixed Cost
Account (NFCA), but will not record any activity to the account other
than amortization revenue and interest after implementation of the Gas
Accord.
g. Customer class charges will be paid by on-system end-users only.
However, loads subject to Line 401 direct connect agreements or EOR
contracts will neither pay, nor be allocated, customer class charges
while the direct connect agreements or contracts are in effect.
h. Forecast customer class charges are shown in Section VI.
10. Customer Access Charge
a. End-users who are directly connected to the transmission system will
pay a customer access charge each month. The purpose of the customer
access charge is to assess the end-user a fee for the cost of
providing and maintaining the individual end-user's service connection
to the transmission system.
b. For industrial end-users, the customer access charges will be the same
as the current industrial customer charge. With the current industrial
customer charge, each end-user is placed in one of six tiers depending
on the end-user's specific annual volumetric usage. There is a
specific monthly charge associated with each tier. Distribution
industrial customers will have the same initial customer access charge
as part of their distribution rates.
c. The UEG and cogenerator customer access charges will be based on the
annual scaled marginal customer cost revenues adopted in BCAP Decision
95-12-053. For UEG, the customer access charge is a monthly charge.
For cogeneration end-users, the customer access charge will be a
volumetric adder, calculated such that the UEG-cogeneration rate
parity is maintained. For cogeneration end-users currently on Schedule
G-CGS, the volumetric adder will equal UEG customer access charges for
twelve months divided by the UEG average annual forecasted throughput
adopted in BCAP Decision 95-12-053. For cogeneration end-users
currently on Schedule G-EPO, the volumetric adder will equal the UEG
monthly
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customer charge divided by UEG actual monthly throughput, lagged by
sixty days.
d. For wholesale customers, the customer access charge for each month of
1997 will equal the scaled annual marginal customer cost revenues
adopted in BCAP Decision 95-12-053 for each specific wholesale
customer divided by twelve.
e. Customer access charges escalate at 2.5 percent per year annually.
f. Current customer access charges are shown in Section VI.
g. Customer access charges for transmission level customers are
guaranteed for the Accord period, subject only to z-factor changes
described in Section II.I.7.
11. Cogeneration Rate Parity
a. On-system cogeneration tariff transmission rates will be available to
all cogenerators, including EPO3 cogenerators, from PG&E's
transmission department. For each path and service, cogenerator rates
will be set equal to the average Utility Electric Generation (UEG)
rate for that path and service. UEG negotiated rates received from
PG&E's transmission department will be included in the rate
calculations on a weighted average,/1/ path specific, service-
-
specific/2/ basis. PG&E will develop, in cooperation with
-
cogenerators, a-mechanism to incorporate UEG negotiated rates into
cogeneration rates.
b. In the event that the current methodology used to determine payments
to EPO3 cogenerators changes so that it is no longer based on actual
UEG natural gas costs, PG&E will negotiate with EPO3 customers in good
faith to develop a method for calculating EPO3 natural gas
transmission service rates which maintains the linkage between EPO3
cogenerators' transmission rates and their electricity payments. Such
resulting rates would be subject to CPUC approval and will apply only
until the expiration of the EPO3 payment option.
- -------------------
/1/ That is, the firm service rate for cogenerators will be calculated using
-
any-negotiated rates for firm service for UEG weighted by volume; similarly, the
As-available service rate for cogenerators will be calculated using any
negotiated rates for As-available service for UEG weighted by volume.
/2/ For purposes of this paragraph, the term "service specific" shall refer
-
to-either firm service or As-available service (including negotiable rate, non-
negotiable rate and other variations of such service) and indicates the
distinction between firm and As-available as separate services.
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c. Transportation services provided to the UEG by entities other than
PG&E's transmission department will not be included in the
cogeneration rate calculations. The UEG includes only PG&E-owned
utility fossil-fired generation facilities. If the UEG does not take
any service from PG&E's transmission department on a particular path
for a particular service, the on-system cogeneration tariff rates for
that path and service will equal the otherwise-applicable cogeneration
tariff rates for that path and service.
d. On-system cogeneration transmission rates will be available only to
cogeneration end-users for their own usage up to the authorized
cogenerator gas allowance./3/ If the cogeneration rate parity statute
-
(Public Utilities Code Section 454.4) is amended or repealed so that
"rate parity" is no longer required by statute,/4/ and if the CPUC
-
for whatever reason no longer requires such rate parity, then there
will be no separate transmission tariff rates applicable to
cogeneration end-users. For purposes of this paragraph, PG&E shall be
free at any time (following the amendment or repeal of the
cogeneration rate parity statute so that "rate parity" is no longer
required by statute) to file a superseding tariff for cogenerators
with the CPUC, which filing may be the occasion for the CPUC to
reevaluate the requirement for such rate parity. Cogenerators
expressly retain the right to oppose such a filing by PG&E./5/
-
e. An on-system cogenerator's monthly bill for non-discounted tariff
service provided by PG&E's transmission department shall be the
minimum of the bill calculated using the transmission rates described
above, and the bill calculated using the otherwise-applicable tariff
transmission rates for that path and service.
f. During open seasons for intrastate transmission capacity, PG&E will
notify on-system cogenerators of UEG's elections for service from
PG&E's transmission department three business days prior to the date
that cogenerators must make their service elections. PG&E will also
notify on-system cogenerators of UEG's other elections for service
from PG&E's transmission department as they may occur
- -----------------------
/3/ The cogenerator gas allowance is not to be determined by the Gas Accord,
-
except that it will remain within 10 percent of 0.09683 th/kWh.
/4/ The Gas Accord does not restrict either PG&E or cogenerators from seeking
-
legislative changes to P.U. Code Section 454.4, but the parties shall support
the provisions of the Gas Accord before the CPUC.
/5/ The provisions of this section are not intended to limit parties'
-
abilities to address before the CPUC any issue they think appropriate dealing
with the divestiture of PG&E generation units. This could include discussion of
any cogeneration rate parity topics as they might relate in any way to divested
units.
-43-
from time to time. This will apply only to UEG service agreements
whose durations are more than 30 days.
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III. DISTRIBUTION SERVICES
A. SERVICES FOR NONCORE END-USERS
1. Distribution transportation service: Noncore customers connected to
PG&E's distribution system may arrange for transmission, storage,
and supply services separately. These customers receive noncore
distribution service from PG&E.
2. Core subscription: Noncore customers may have PG&E arrange for
their supply and transmission service under core subscription
service, described in Section IV.M.
3. Residual load service: PG&E will propose a residual load service in
the next BCAP.
B. SERVICE FOR CORE END-USERS
1. PG&E will continue to provide bundled service for coreend-users.
See Section IV for changes that may affect core service.
2. PG&E will also provide core transport service for core end-users.
See Section IV for a discussion of core aggregation.
C. RATES AND COST ALLOCATION
1. Distribution Revenue Requirement Assumptions
a. The initial natural gas distribution revenue requirement will
match PG&E's 1996 GRC Decision 95-12-055, consistent with the
transfer of DFMs to local transmission. Customer access charges
for transmission-level end-users have been moved from the
distribution revenue requirement to the customer access charge.
b. The distribution revenue requirement in future years of the Gas
Accord will be based on cost of service or Performance Based
Regulation (PBR), whichever is applicable. For the purposes of
calculating the illustrative rates shown in Table 16 in Section
VI, the revenue requirement escalates at 2.5 percent per year.
2. Distribution Cost Allocation
a. The initial distribution revenue requirement will be allocated to
end-users on an Equal Percent of Marginal Cost (EPMC) basis, using
distribution and customer marginal cost revenues consistent with
PG&E's BCAP Decision 95-12-053.
b. PG&E will continue to have BCAPs and GRCs or successor proceedings
to update the allocations of costs. The methodology for allocating
the distribution revenue requirement between core and noncore will
not be changed for the term of the Gas Accord, although the
allocation itself may change due to, among other
-45-
things, changes to throughput forecasts or marginal costs. The
allocation of revenues within the core will be addressed in
future BCAPs.
3. Distribution Throughput
a. Distribution throughput for noncore end-users has been modified to
reflect loads served directly from the transmission system, as
well as end-users connected to the distribution system but
classified as transmission customers.
b. Core and noncore throughput forecasts will be addressed in future
BCAPs or PBRs.
4. Balancing Account Treatment
a. PG&E's core procurement department's cost of intrastate backbone
and local transmission service for the core will receive 100
percent balancing account treatment for the costs incurred, either
through the Core Fixed Cost Account (CFCA) or the Purchased Gas
Account (PGA).
b. The core distribution revenue requirement will continue to
receive 100 percent balancing account treatment.
c. Balancing account treatment (Noncore Fixed Cost Account) for
prospective noncore distribution revenues will be eliminated.
5. Shrinkage
a. Noncore customers and core transport customers will continue to
deliver in-kind shrinkage. Bundled core end-users and core
subscription customers will continue to pay shrinkage as part of
their procurement rate.
b. Shrinkage will be charged on the distribution system on a postage-
stamp basis for all gas deliveries. Distribution shrinkage is in
addition to any shrinkage applied on the transmission system.
c. Distribution shrinkage is calculated using percentages authorized
in PG&E's most recent BCAP Decision 95-12-053, as follows: the
core distribution shrinkage rate (including core transport) is
3.31 percent, and the noncore distribution shrinkage rate is 0.21
percent. These percentages are subject to change in future BCAPs.
The core shrinkage subaccount will continue as currently
authorized.
6. Distribution Rates and Rate Design
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a. Forecast distribution rates and illustrative intrastate bundled
core transportation rates are shown in Section VI.
b. The initial core commercial winter distribution rate component
will remain at 135 percent of the summer distribution rate
component. For core commercial customers taking bundled service
from PG&E, intrastate transmission costs will be allocated into
the season in which they are incurred, and storage costs will be
included in winter season rates only. Commodity costs will not be
included in any seasonal rate differential calculation.
c. The initial noncore winter distribution rate component will be
135 percent of the summer distribution rate component.
d. Future distribution rate design, rates, residential tier
differentials, and core deaveraging, among other things, will be
determined in future BCAPs. Parties also reserve the right to
propose other cost-based core cost allocation and rate design
changes in future BCAPs.
7. Cogeneration Rate Parity
a. Consistent with the CPUC's cogeneration rate parity policy,
distribution level cogenerators will not have a distribution
component in their rate. The resulting "cogeneration shortfall"
will be a part of the customer class charge, and will be collected
from cogeneration and UEG end-users, for their own usage up to the
authorized cogenerator gas allowance.
b. If the cogeneration rate parity statute is amended or repealed so
that "rate parity" is no longer required by statute, and if the
CPUC for whatever reason no longer requires such rate parity, then
distribution level cogenerators will be served under the otherwise
applicable distribution rate, and there will be no separate
cogeneration class.
c. PG&E shall be free at any time (following the amendment or repeal
of the cogeneration rate parity statute so that "rate parity" is
no longer required by statute) to file a superseding tariff for
cogenerators with the CPUC, which filing may be the occasion for
the CPUC to reevaluate the requirement for such rate parity.
Cogenerators expressly retain the right to oppose such a filing by
PG&E.
8. Discounting
a. Distribution service may be discounted to prevent uneconomic
bypass of PG&E's distribution system and to encourage business
retention and business attraction.
b. PG&E may negotiate discounts with distribution-level noncore end-
users to prevent uneconomic bypass of PG&E's distribution and
transmission systems, and to encourage business retention and
business attraction.
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c. Any negotiated discounts with core end-users for distribution
service will require CPUC approval prior to going into effect.
d. If the purpose of a noncore discount negotiation is to attract or
retain both transmission and distribution load, any discount will
be "split" between transmission and distribution services
proportional to the revenue to each system at full tariff prices.
The noncore end-use customer would receive the transmission
portion of the discount in a bill credit, or through local
transmission or customer access charges.
e. If a negotiated distribution service benefits only the
distribution system, any discount will be reflected only in
distribution rates.
f. PG&E will have the option in BCAP proceedings of demonstrating the
reasonableness of any discounted distribution contracts that will
continue into the prospective period. If the Commission finds the
discounts to be reasonable, PG&E will be allowed to recover the
forecasted revenue shortfalls during the prospective period.
g. Negotiated contracts and affiliate transactions rules which will
apply to transmission services will also apply to distribution
services. (See Sections II.E.15 and II.E.16.)
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IV. PG&E'S FUTURE ROLE IN CORE PROCUREMENT
A. OVERVIEW
PG&E proposes to reduce costs to customers and to expand core customer
choices by:
1. Encouraging greater customer choice among gas suppliers;
2. Reducing PG&E's regulated sales of gas to core customers;
3. Reducing PG&E's interstate pipeline capacity holdings for the core;
4. Establishing operational principles that provide market flexibility
while ensuring safe and reliable service;
5. Implementing appropriate incentive mechanisms; and
6. Negotiating with California producers for a mutual release of PG&E's
gas purchase contracts and reducing gas gathering costs through the
disposal of assets.
B. CORE PROCUREMENT ADVISORY GROUP
1. Significantly reducing PG&E's role in the core procurement market
requires significant expansion of the current core gas transportation
program. This program now serves only about three percent of the core
load in PG&E's service area, and well under one percent of core
customers.
2. To determine the changes that should be made to the program, PG&E
invited all Gas Accord parties to participate in the Core Procurement
Advisory Group (CPAG). The focus of the CPAG was the development of
recommendations that would accomplish two primary objectives:
a. Make the program consistent with the proposed Gas Accord
framework; and
b. Remove barriers, from both the customers' and aggregators'
perspectives, to increasing program participation.
3. Approximately 50 parties joined PG&E and identified over 40 separate
issues that needed to be resolved. Two working groups were
established to conduct the detailed negotiations necessary to resolve
these issues and balance the widely diverse interests of the parties.
4. After the initial package of recommendations was developed, three
new CPAG working groups were established to facilitate
implementation of the CPAG recommendations:
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a. Market Test: The Market Test work group will participate in the
-----------
development and performance of market research and affinity-
group marketing field tests that are required to enhance core
aggregation in PG&E's service area.
b. Tariff Revisions: The Tariff Revision work group will assist as
----------------
PG&E's tariffs are revised to incorporate the CPAG
recommendations that are ultimately approved in the Gas Accord
proceeding.
c. Load Forecast and Determination Model: The Load Forecast and
-------------------------------------
Determination Model work group will participate in the
development of a model that will be used for core load balancing
purposes.
5. The agreements below reflect the approved package of CPAG
recommendations. The core aggregation agreements are intended to
apply to PG&E's service area. They are not intended to set precedents
for any other utility service area, or for noncore service.
Additional information about the detail behind these proposals can be
found in the CPAG agreement.
C. PG&E'S AND AGGREGATORS' ROLES IN THE CHANGING CORE GAS SALES MARKET
1. As part of its compliance filing following approval of the Gas
Accord, PG&E will file tariffs to lift the ten percent cap on PG&E's
core gas aggregation program.
2. Aggregators have the obligation to make and pay for all necessary
arrangements to deliver gas to PG&E to match the use of their
customers.
3. PG&E has the obligation to operate the gas system safely and
efficiently and to purchase gas supplies for customers not served by
aggregators.
4. PG&E's remaining core gas procurement role will be as a regulated
utility supplier within PG&E's service area during the Gas Accord
period.
5. The CPAG will explore, through market research efforts, several ways
to attract small and highly seasonal customers to core transportation
service and to reduce transaction costs for aggregators to serve
them.
6. PG&E and the aggregators will each be responsible for dealing with
their own customers' payment problems. The allocation of costs to
serve slow- and non-paying customers will be reexamined when PG&E's
core gas sales market share drops to 80 percent.
7. The costs of social and environmental programs such as CARE, clean
air vehicles and customer energy efficiency will continue to be
recovered from all on-system end-users through the customer class
charge component of the transportation rates.
8. CARE core transportation customers will receive the full CARE
benefits regardless of their choice of gas supplier.
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D. REDUCING PG&E'S INTERSTATE PIPELINE CAPACITY
PG&E will adjust its core capacity holdings of firm interstate pipeline
capacity as follows:
1. PG&E's contract with El Paso will terminate at the end of 1997. As
part of the current El Paso general rate case (FERC Docket Nos. RP95-
363-000, et al.), PG&E's termination of this contract, as well as
other utility contract step-downs and the related costs, are
addressed in a settlement filed with the FERC on March 15, 1996. The
parties agree that any costs paid by PG&E resulting from the FERC-
approved settlement will be treated as one component of the overall
interstate pipeline reservation charges; and therefore, will be
allocated to core and noncore customers using the allocation
methodology for interstate pipeline reservation charges adopted in
PG&E's BCAP Decision 95-12-053.
2. PG&E reserves the right to subscribe to additional interstate
capacity in the future, with costs assigned to PG&E's core
procurement customers.
3. Other reductions may be made by PG&E (as allowed by PG&E's
interstate capacity contracts) as core aggregators' share of the
core market increases.
E. PG&E'S CORE PROCUREMENT DEPARTMENT INTRASTATE PIPELINE AND STORAGE
CAPACITY
1. PG&E's core procurement department will hold intrastate
transportation capacity on behalf of its core and core subscription
customers. The following initial firm reservation of intrastate
transportation capacity will be made for the retail core:
a. PG&E's retail core initially will be allocated the following
quantities of firm transmission capacity:
Malin to Topock to
On-system On-system California
--------- ---------- ----------
Annual MMcf/d 600 150 50
Mdth/d 609 155 48
b. PG&E's retail core will also hold additional seasonal winter
capacity as follows:
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Malin to Topock to
On-system On-system California
--------- --------- ----------
November and March
MMcf/d 0 150 0
Mdth/d 0 155 0
December to February
MMcf/d 0 450 0
Mdth/d 0 464 0
2. The initial firm allocation of Malin capacity for the retail core
will be priced at vintaged rates.
3. PG&E's core procurement department will continue to be allocated firm
rights to a portion of storage capacity on behalf of the core market,
as specified in Section II.E.5. The core's storage and other costs
related to maintaining the safe and reliable operation of the gas
system will be included in core rates.
F. CORE AGGREGATORS' HOLDINGS OF INTERSTATE CAPACITY
1. PG&E will make two filings to unbundle interstate transmission costs
from core transport rates within 30 days after a comprehensive Gas
Accord agreement is signed.
a. The first filing will address unbundling prior to January 1,
1998. This filing will:
i. unbundle PGT and El Paso capacity;
ii. impose a surcharge on core transport rates until January 1,
1998, not to exceed $0.19/Dth, to cover any resulting
transition costs;
iii. continue the present treatment of ANG and NOVA costs; and
iv. implement the rate credit described in Section IV.G.6.
b. The second filing will address unbundling after January 1, 1998,
when PG&E's El Paso contract will expire. This filing will:
i. continue unbundling of PGT capacity; and
ii. provide that, once the core transport share of PGT core
capacity exceeds the point where PG&E's remaining PGT core
capacity matches its upstream rights on ANG and NOVA,
approximately 40 MMcf/d, core aggregators taking a share of
PGT core capacity will have the right, but not the
obligation, to accept a proportionate share of ANG and NOVA
capacity, to the extent it is available, for additional PGT
capacity reservations.
iii. provide that, to the extent that core aggregators taking a
share of PGT core capacity choose not to take a
proportionate share of ANG and NOVA
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capacity, PG&E will have the right to offer to assign the
capacity to other shippers for one month up to the duration
of PG&E's contracts with ANG and NOVA. This may result in
core aggregator's not having access to this capacity in the
future. If PG&E chooses not to make such an offer, or is not
successful in finding shippers for the full amount offered,
PG&E will broker the capacity.
iv. provide that, 50 percent of the difference between the cost
of PG&E's contractual obligations for the proportionate
share of ANG and NOVA capacity offered to, but not taken, by
core aggregators, and the revenues collected by PG&E as a
result of brokering efforts for that capacity will be
allocated to the transportation rates paid by PG&E's core
transport customers. PG&E's shareholders will be at risk for
the remaining 50 percent.
2. Core aggregators will choose their own interstate pipeline capacity
mix. Each month, core aggregators will have a preferential right
(but not the obligation) to acquire a portion of PG&E's interstate
capacity holdings to serve their core customers.
3. If core aggregators choose not to acquire PG&E's firm capacity
rights, or if this capacity is marketed at less than as-billed rates,
unrecovered pipeline reservation fees will become a transition cost,
subject to the $0.19/Dth cap in Section IV.F.1.a.ii above until
January 1, 1998.
4. Beginning January 1, 1998, any pipeline transition costs resulting
from existing PGT commitments on behalf of core transport customers
will be allocated to all core customers for the term of the Gas
Accord. This provision will be reexamined if transition costs exceed
$5 million per year.
G. CORE AGGREGATORS' HOLDINGS OF INTRASTATE CAPACITY AND STORAGE
1. Intrastate transmission costs will be unbundled from core
aggregation customers' rates effective with the Accord.
2. For the initial two years of the Gas Accord, aggregators must hold
firm intrastate transmission capacity rights during the winter season
equal to a proportional share of PG&E's initial core reservation
during the five winter months, excluding the California on-system
reservation. Thereafter, aggregators who perform reliably will have
no firm requirements.
3. Aggregators may choose the transmission path of their reservation.
They are entitled, though not obligated, to subscribe to a
proportional share of the vintage-priced Malin to on-system core
reservation and/or a proportional share of the Topock to on-system
reservation.
4. Aggregators may also use the following alternatives to meet their
firm intrastate transmission requirements:
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a. Standard agreements to use other firm holders' rights when
needed;
b. California gas supplies; or
c. Firm storage capacity in addition to their assigned capacity, if
available.
5. Aggregators will continue to be assigned a proportional share of
PG&E's core storage reservation based on the winter season throughput
of the core transport customers (consistent with CPUC Decision 95-07-
048), with the obligation to fill it and maintain minimum inventory
levels for reliability purposes. However, to the extent possible
without compromising the reliability functions of storage for core
customers, aggregators will have the right to use storage balances
above each aggregator's minimum level described in PG&E's G-CT tariff
to cure imbalances, to make same-day injection and withdrawal
nominations, and to sell or trade gas in storage.
6. Within three years after the Gas Accord is implemented, PG&E will
file with the CPUC an examination of storage unbundling for core
transportation customers in light of the then-existing market.
7. In recognition of the fact that aggregators have settled for less
service unbundling than they preferred, and to encourage
participation in the core transportation program, PG&E's shareholders
will fund a $0.095/Dth credit to core transport rates until January
1, 1998.
H. CORE AGGREGATION REGULATORY ISSUES
1. The PG&E core procurement brokerage fee will be set at $0.024/Dth and
will be subject to balancing-account recovery. This fee will be
reviewed when PG&E's market share drops to 80 percent.
2. In compliance with the provisions of California Public Utilities Code
Sections 6350 - 6354, PG&E will continue to collect city/county
franchise fees for service provided by aggregators based on its own
weighted-average cost of gas (WACOG). PG&E will seek legislative
changes to allow similar treatment for utility users' taxes.
3. Billing and metering costs will remain bundled. PG&E will install
additional metering at the request/expense of aggregators and their
customers, and will provide a credit if PG&E equipment can be removed
as a result.
4. PG&E will continue to oversee aggregators' creditworthiness,
pursuant to PG&E's Gas Rule 23, Gas Aggregation Service for Core
Transport Customers.
5. Aggregators will continue to be required to sign a core transport
agreement with PG&E. Aggregator-customer contracts are strictly
between the parties.
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6. Customers must sign a PG&E agreement for service from an aggregator
for an initial term of 12 months. PG&E will conduct market research
to see if this requirement is a significant barrier to program
participation.
7. In order to prevent slamming (unauthorized switching of a customer
from one aggregator to another), written consent will continue to be
required from customers who want to change their gas aggregators.
8. Aggregators may obtain PG&E customer information required to select
and serve their customers (such as balances owed and customer-service
details) when authorization is given by the customer.
9. PG&E will provide aggregators with a list of qualified gas-supply
businesses owned by minorities, women, and disabled veterans that may
be used when purchasing gas supplies. PG&E will also provide gas-
supply businesses owned by minorities, women, and disabled veterans
with a list of qualified core aggregators and other information
needed to participate in PG&E's core gas transportation program.
10. The minimum size for a core transport group will be lowered from
250,000 therms per year to 120,000 therms per year.
11. After three years, PG&E will file a core transport program status
report with the CPUC, and PG&E will hold a workshop to address any
difficulties that have arisen with respect to PG&E's core gas
transportation program.
12. The modifications for core aggregation are designed so that they do
not have a significant adverse impact on PG&E's remaining core
procurement customers.
I. CORE AGGREGATION AND CUSTOMER INFORMATION
1. Customers of aggregators may continue to select a consolidated
payment option, where aggregators in compliance with PG&E's Gas Rule
23 creditworthiness standards collect and forward to PG&E appropriate
transportation revenues from their customers, as long as the payments
to PG&E are on time.
2. PG&E and the aggregators will work together to develop a common
Electronic Data Interface (EDI) protocol, which all aggregators will
then be required to use, to streamline data and monetary transfers
necessary to serve their customers.
3. PG&E will continue to promote the core transportation program to
customers through periodic bill inserts and provision of aggregator
lists upon customer request. PG&E will also promote the core
transportation program to its own employees through an internal
education program.
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4. PG&E will conduct a market test to see if outreach efforts through
affinity groups (e.g., city governments, schools, churches) are
effective in increasing program knowledge and participation and
reducing aggregators' transaction costs.
5. PG&E call centers will be equipped to handle calls about the core
transportation program.
6. PG&E will provide aggregators with a bill insert that they may use to
ensure that their customers know to call PG&E for service- or safety-
related questions. Aggregators will refer all such calls that they
receive from their customers to PG&E.
J. CUSTOMER AGGREGATION SERVICE AND OPERATIONAL ISSUES
1. PG&E will provide aggregators with a new Core Load Forecasting and
Determination Service. This service will feature 24- and 48-hour
forecasts and day-after estimated ("determined") use, based on each
aggregator's customer mix.
2. The sum of the daily determined use figures will be used to calculate
monthly imbalance volumes and penalties.
3. The difference between the monthly sum of the daily determined use
figures and the prorated monthly metered use for each aggregator's
customers will be the "operating imbalance." The operating imbalance
will be disposed of during the next month. However, operating
imbalances of more than 10 percent of monthly use can be disposed of
over two months.
4. By 5:00 p.m. on the day before an Operational Flow Order or Emergency
Flow Order, PG&E will provide an additional forecast to aggregators
for their customers' next-day usage. Aggregators will be required to
balance against that forecast during the OFO or EFO.
5. When an aggregator collects PG&E transportation revenue from
customers under the "consolidated payment" option, PG&E will hold the
aggregator responsible for late payment or non-payment to PG&E if the
customer can demonstrate that it has paid the aggregator in full and
on time. PG&E will not hold the customer responsible .
6. The following recommendations were made in order to provide clear,
prompt, and responsive information to address customer concerns:
a. PG&E and the aggregators will negotiate the establishment of
joint communications protocols, to allow seamless call and
information transfers.
b. PG&E and the aggregators will negotiate an industry "decision
tree" for screening customer inquiries, to determine the party
responsible for responding to the customer.
K. CORE WHOLESALE CUSTOMERS
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1. Wholesale customers have the obligation to plan to meet their own
core loads.
2. Existing wholesale customers, Palo Alto and Coalinga, will have a
one-time option at the implementation of the Gas Accord to
subscribe, on behalf of their core customers, for up to 6.5 MMcf/d
(6.6 Mdth/d) of firm capacity on the Malin to on-system path at
vintaged rates.
3. Existing wholesale customers will have the right to a share of
storage capacity. They will get first priority from the storage
capacity allocated to the Unbundled Storage Program, equal to their
proportional share of the core load. They must reserve inventory,
injection, and withdrawal proportionately together and they will pay
the equivalent core rate for storage. Any storage cost will be added
to the wholesale customer's transportation rate. They will have the
same storage rights as other entities serving core customers and they
may contract for storage through the Unbundled Storage Program to
serve their noncore customers.
L. PROCUREMENT INCENTIVE MECHANISMS
1. For the period June 1, 1994, through December 31, 1997, PG&E will
recover procurement and transportation costs consistent with the
revised CPIM mechanism negotiated with DRA in 1996, and submitted as
testimony by PG&E on April 23, 1996, in Application 94-12-039. As a
result, this will resolve core procurement reasonableness for such
period. Further, as part of such testimony, PG&E will forego its
right to seek recovery of the reservation charges associated with the
150 MMcf/d Transwestern core reservation for the periods 1992-1997.
2. A post-1997 procurement incentive mechanism will be based on the
following parameters:
a. The pre-1998 CPIM agreement with DRA will be used as a model
for the new incentive mechanism.
b. The mechanism will be modified to include intrastate core
capacity use (both firm and as-available).
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c. The mechanism will be modified to allow for the opportunity to
recover the cost of Transwestern reservation charges for 150
MMcf/d, as well as other Southwest interstate capacity
requirements that the core may require.
d. PG&E will develop a procedure to recover the costs associated
with diversion and balancing penalties in rates that may occur
under extreme weather or other extraordinary circumstances.
e. Based on the above parameters, PG&E and DRA will agree on the
detailed substance of their post-1997 mechanism and amend this
Gas Accord Settlement filing with the CPUC.
M. CORE SUBSCRIPTION
1. Operations
a. Core and core subscription customers will be served by PG&E
through a single supply portfolio.
b. Capacity reservations, nominations, and balancing will take place
for the portfolio as a whole.
c. Core subscription customers will be assumed to use a
proportional share of reserved interstate, Canadian and
intrastate capacity.
d. Core subscription customers will be assumed to use a
proportional share of the core portfolio's flowing supplies.
e. Transmission service priority for core subscription customers
under emergency conditions will be the same as the priority of
firm intrastate transmission service.
2. Pricing
a. Core subscription rates will be volumetric.
b. The intrastate transmission capacity charges for core
subscription will be based on the transmission rates for the
noncore market. That is, core subscription will not receive
vintaged Malin to on-system prices. Core subscription revenues
above the core subscription's proportionate share of the core
portfolio's intrastate capacity costs will be returned to core
customers served from the portfolio.
c. The PGT capacity costs for core subscription will be set at a
weighted average (based on the available capacity) of the FTS-1
"Noncore" and the FTS-1 "Expansion Shipper" reservation rates, as
specified in PGT's FERC-approved tariffs. Core subscription
revenues above the core subscription's proportionate share of the
core portfolio's PGT capacity costs will be returned to core
customers served from the portfolio.
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d. The cost of southwest pipeline capacity for core subscription is
set at its cost.
e. The Canadian capacity charges for core subscription will be at
the as-billed rate.
f. There will be a surcharge on core subscription rates of $0.07/Dth
beginning January 1, 1998, to fund activities associated with
program phase-out. Unspent revenues from the surcharge remaining
after the core subscription program is discontinued will be
returned to the core subscription customers which initially paid
the surcharge.
g. Each core subscription customer will be responsible for any
customer-specific penalties for failing to curtail use when
requested by PG&E under the involuntary diversion provisions.
Core subscription customers will not be responsible for any
involuntary diversion penalties incurred by the core portfolio.
h. Except as just described, the core subscription rate will include
core subscription's pro rata share of all core portfolio costs.
Among other things, this includes Southwest interstate and
Canadian capacity costs, as well as any imbalance charges,
voluntary diversion payments, and costs or credits associated
with the risk-sharing provisions of the core procurement
incentive mechanism.
i. The core subscription rate will be set monthly based on a
forecast of the core portfolio costs.
j. The core subscription monthly commodity price will be set at the
forecasted average cost of core portfolio flowing supplies (no
gas out of storage), adjusted as necessary to reflect any prior
months' forecast error in the core portfolio commodity cost.
k. The core subscription rate will also be adjusted as necessary to
reflect any prior period forecast errors associated with
Canadian, interstate and intrastate capacity (net of brokering
revenues).
l. Adopted shrinkage costs will be collected from core subscription
customers.
m. Balancing account treatment for core subscription commodity,
interstate and Canadian capacity, and shrinkage will be
eliminated prospectively.
n. The core subscription rate will include a component to amortize
the accrued balances from the current balancing accounts.
o. PG&E's noncore brokerage fee will remain at $0.0382 per
decatherm, with balancing account treatment. Balances will
continue to be allocated equal cents per therm to all noncore
customers.
3. Eligibility for Core Subscription Service
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Any noncore customer on PG&E's system, excluding UEG, is eligible for
core subscription service.
4. Core Subscription Service Phaseout
a. Core subscription service is to expire within three years after
implementation of the Gas Accord. At that time, customers wishing
to remain PG&E procurement customers must elect to become core
customers.
b. Parties may propose cost-based rate design changes in a future
BCAP to mitigate the price impact on such customers who choose
core status.
c. PG&E will conduct a marketing campaign to ensure that core
subscription customers are aware of the competitive procurement
alternatives available to them. The cost of the marketing
campaign will be offset against the revenues from the $0.07/Dth
surcharge.
5. Contract Terms
a. One-year term.
b. Current contracts will remain in effect until their expiration on
July 1, 1997, except that current core subscription customers
will be allowed to change suppliers before the expirations of
their current contracts.
c. If the core subscription program participation (numbers of
customers or contracted load) increases by more than ten percent
(35 customers or 4 MMcf/d), the parties will confer to consider
possible responses.
N. CHANGING PG&E'S ROLE IN NORTHERN CALIFORNIA GAS PRODUCTION
1. PG&E has had a strong presence in the northern California gas
production industry both as the largest purchaser of gas and the
largest gas gatherer. The Gas Accord proposes to reshape that role
and seeks approval of the principles advocated here. Many of the
implementation details that underlie these changes will of necessity
be part of separate proceeding(s).
PG&E and California producers intend to provide for efficient
operation of the facilities used to bring California gas to market
and to extend the economic life of California gas production.
2. PG&E proposes several principles that would apply to northern
California gas production. They are:
a. The mutual release of all California production gas procurement
contracts held by PG&E.
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b. PG&E will support the formation of a non-utility cooperative run
and managed by an association of producers (the Cooperative) or
of a utility corporation run and managed by an association of
producers (the Utility) to purchase and operate the gas gathering
system. The Utility or Cooperative shall protect producer
interests through an opportunity to participate in ownership and
in governance; to have access to information; and to participate
in profits, if any. PG&E's support is limited to a gas gathering
entity. PG&E will not seek to spin-down the gathering facilities
to an unregulated affiliate.
c. The sale of as many of the gas gathering facilities as possible
to the Cooperative or the Utility, or to individual producers who
are served by those facilities. Assets presently designated as
gathering that are needed to provide safe and reliable
transmission or distribution service will be retained and
redesignated. PG&E will identify and connect producers on
redesignated portions of the gathering system to the
Utility/Cooperative gathering system(s) to assure access to
market.
d. Should the Cooperative or the Utility not be formed or not
purchase all the facilities, PG&E shall divest as many facilities
as possible to producers where those facilities are only used by
those producers.
e. If gathering facilities cannot be divested at a fair market
price, PG&E will continue to own and maintain those facilities
while recovering the ongoing costs of such facilities directly
from producers that use them through a gathering charge. The
level of the gathering charges will not exceed the difference
between the California path rate and the lowest noncore
transmission path connected to interstate gas supplies.
f. Where the Utility, the Cooperative, or individual producers
acquire or provide their own gathering, the California path rate
will be reduced by a cost-based credit. The cost-based credit
shall be volumetric and shall be afforded to producers on a basis
that reflects facilities acquired and costs avoided.
g. Approval of the sale of gas gathering facilities is pursuant to
Section 851 of the California Public Utilities Code, on such
terms and conditions as are mutually acceptable to the parties.
To the extent there is a gain-on-sale related to the disposition
of gathering facilities, the gains will be shared 95 percent
ratepayer and 5 percent shareholder. To the extent there is a
loss-on-sale, PG&E's shareholders will absorb 100 percent of the
losses. In determining whether or not a gain- or loss-on-sale has
occurred, PG&E will use a net book value based on the
depreciation methodology outlined in Decision 89-12-016, the gas
gathering decision. Gains would be included in an interest
bearing balancing account, reflected in rates in the appropriate
rate proceeding. Any environmental clean-up necessary for the
sale will be recoverable via the Hazardous Substance Mechanism
balancing account or through the appropriate mechanism as may be
authorized by the Commission.
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h. Approval and implementation of a standard California Production
Balancing Agreement to meet one of PG&E's goals of improving the
efficient use of its gas transportation system by reducing delays
caused by adjustments when wellhead meter data do not match
scheduled volumes. This will be effected by filing a pro forma
agreement in an advice filing, subject to protest by producers.
i. Cooperate with the California gas producer community to develop
options that will allow gas gatherers access to pipeline pressure
data to maximize gathering system operational flexibility and to
assist with the management of production imbalances.
j. Approval and implementation of a standard California Production
Interconnection and Operating Agreement to apply consistent
requirements whenever facilities owned by producers, by the
Utility, or by the Cooperative are interconnected with PG&E's
system for the purpose of gas transportation and authorization of
an operations and maintenance fee, where applicable. Both will be
effected through an advice filing, subject to protest by
producers.
k. Any California-produced gas that PG&E buys outside of its
existing contracts will meet the same quality standards as all
other transported California-produced gas. PG&E will endeavor to
continue its historic practice of transporting low-Btu gas to the
extent physically possible, based on historical volumes.
California produced gas that does not meet PG&E's minimum heating
value requirement and/or gas quality specifications as set forth
in PG&E's Rule 21 that is sold directly to end-use customers of
PG&E is exempt from the residual load service tariff.
l. Should the Utility form for the purpose of acquiring and
operating the gas gathering system, PG&E will support a filing
for "light-handed" regulation for the Utility by the commission.
"Light-handed regulation" shall be consistent with protecting
producer interests through the provision of gathering services at
the lowest reasonable cost; participation in ownership;
participation in governance; access to information; assurances
against discrimination; and participation in profits. PG&E's
support for "light-handed" regulation is limited to a gas
gathering entity.
3. The implementation of the Gas Accord could affect the employees of
PG&E. With respect to PG&E's International Brotherhood of Electrical
Workers (IBEW) workforce, PG&E will work with the IBEW to minimize
the impact on employees. In the event that PG&E sells gas gathering
facilities, as discussed above, and the sale results in the need to
reduce the workforce, PG&E may offer a Voluntary Severance Incentive,
a Voluntary Retirement Incentive, retraining, and other employee
options, subject to negotiation with the IBEW local 1245.
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V. LITIGATION RESOLUTION
A. OBJECTIVES
To resolve the outstanding proceedings relating to PG&E's natural
gas operations as a means of transitioning to a restructured, more
competitive gas business. Settlement of all these cases and the
outstanding issues in these cases pursuant to the provisions below is a
prerequisite to implementation of the Gas Accord.
B. REGULATORY CASES ADDRESSED BY THE ACCORD
1. The Gas Accord settles and resolves the outstanding gas issues in the
following proceedings, except as otherwise noted in this document:
a. PG&E's 1992 through 1995 gas reasonableness cases, Applications
93-04-011, 94-04-002, 95-04-002, and 96-04-001;
b. All issues in Phases 1, 2, and 3 of the combined Pipeline
Expansion Project Reasonableness/Interstate Transition Cost
Surcharge proceeding, and also the alleged Rule 1 violation,
covered in Applications 92-12-043, 93-03-038, 94-05-035, 94-06-
034, 94-09-056, and 94-06-044;
c. All issues regarding the reasonableness of noncore capacity
brokering from January 1, 1996, through December 31, 1997.
(Noncore and core capacity brokering for 1993-1994 is addressed
in 1.b above. Noncore capacity brokering for 1995 is addressed in
1.a above. Core capacity brokering practices from June 1, 1994,
to December 31, 1997, are addressed through PG&E's revised CPIM);
d. All issues in the Core Procurement Incentive Mechanism case,
Application 94-12-039;
e. The EAD shortfall issues addressed in Applications 92-07-047,
92-07-049, 95-02-008, and 95-02-010;
f. Phase 2 of PG&E's BCAP Application 94-11-015; and
g. All issues pertaining to the reasonableness, restructuring, and
revision of PG&E's transmission, storage, and core procurement
practices, rates, and services in various statewide rulemaking
and investigation dockets, R.88-08-018, R.90-02-008, R.92-12-016,
and I.92-12-017.
2. PG&E has omitted the Canadian procurement (including the effects on
northwest, geothermal and QF purchases), Canadian Decontracting and
Restructuring, ANG and NOVA capacity, Affiliate Investigations, CIG
sequencing, UEG curtailment, and Southwest procurement (including the
Satrap investigation) issues in the 1991-1994 gas reasonableness
cases from the list of financial concessions. These issues have
-63-
been settled separately through May 1994, and the settlements have
been filed with the CPUC. Therefore, they are not included in the
financial concessions being considered as part of the Gas Accord.
C. SETTLEMENT OF REGULATORY CASES AND PG&E FINANCIAL CONCESSIONS
1. Transwestern Pipeline Capacity Charges - Core 150 MMcf/d Contract
-----------------------------------------------------------------
(A.93-04-011, 94-04-002, 94-12-039, 95-04-002, 96-04-001, and PG&E's
application covering reasonableness for 1996 and 1997, when filed)
PG&E will not seek to recover any pipeline demand charges associated
with the core portion of the Transwestern contract from the
initiation of the contract through December 31, 1997, consistent with
PG&E's revised CPIM submitted on April 23, 1996. (See Section IV.L.)
For the period after 1997, PG&E will recover Transwestern demand
charges for the balance of the Transwestern contract term in
accordance with a successor CPIM which will be implemented January 1,
1998. Accordingly, if the Gas Accord, including PG&E's revised CPIM,
is approved, PG&E will withdraw any appeal of Decision 95-12-046.
2. ANG and NOVA Pipeline Capacity Charges
--------------------------------------
(A.94-12-039, 95-04-002, 96-04-001, and PG&E's application covering
reasonableness for 1996 and 1997, when filed)
For the period from June 1, 1994, through December 31, 1997, PG&E
will recover core ANG and NOVA capacity demand charges in accordance
with PG&E's revised CPIM. (See Section IV.L.) For the period after
1997, PG&E will recover ANG and NOVA demand charges for the balance
of the ANG and NOVA contract terms at full ABR in accordance with a
successor CPIM which will be implemented January 1, 1998.
3. Transwestern Pipeline Capacity -- UEG 50 MMcf/d Contract
--------------------------------------------------------
(A.93-04-011, 94-04-002, 95-04-002, and 96-04-001)
PG&E agrees to resolve the UEG Transwestern Capacity of 50 Mdth/d as
follows: PG&E will not seek to recover from ratepayers the
reservation charges associated with the 50 Mdth/d of UEG Transwestern
capacity incurred through July 31, 1993. Recovery of reservation
charges from August 1993 through implementation of the Power Exchange
(PX) will be determined by comparing UEG's monthly commodity and
volumetric interstate transportation costs associated with UEG's 50
Mdth/d of Transwestern capacity contract to a market benchmark based
on California border indices. The benchmark will be calculated by
multiplying an average of Topock gas price indices by the volumes
transported by UEG for the month on the 50 Mdth/d of Transwestern
capacity. The difference between the benchmark and the UEG commodity
and the volumetric interstate transportation costs will be the amount
of Transwestern reservation costs PG&E will be allowed to recover.
The average border price will be determined by a simple average of 30
day Topock gas price indices from the following publications: Gas
Daily, Natural Gas Weekly and Natural Gas Intelligence Gas Price
Index. Recovery of reservation charges after implementation
-64-
of the PX will not be through the proposed Competitive Transition
Charge (CTC) mechanism.
PG&E is entitled to all revenue from brokering UEG Transwestern
capacity generated through the period of the contract.
For the period prior to December 31, 1995, PG&E would recover $3.7
million of its total Transwestern capacity costs plus brokering
revenues. The appropriate adjustments will be made to PG&E's ECAC
balancing account to reflect this agreement. It is further agreed
that this agreement will set no precedent for the treatment of other
capacity reservations that the UEG may incur from time to time.
4. Pipeline Expansion Project Reasonableness (PEPR)/Interstate
-----------------------------------------------------------
Transition Cost Surcharge (ITCS) Proceeding
-------------------------------------------
(A.92-12-043, 93-03-038, 94-05-035, 94-06-034, 94-09-056, 94-06-044,
and 96-04-001)
Implementation of the terms and agreements of the Gas Accord, as
proposed, settles all contested issues associated with Phases 1, 2,
and 3, of the PEPR/ITCS case, and also Rule 1 allegations.
a. ITCS Account (Core portion)
---------------------------
PG&E will absorb 100 percent of the core portion of ITCS charges
as currently defined, less brokering revenues, plus interest,
from the inception of the ITCS account. Any ITCS costs that were
recovered in rates from the core will be returned to the core.
Consequently:
i. PG&E will not be responsible for any proposed additional
Northern California ITCS costs or other penalties or remedies
alleged in the PEPR/ITCS proceeding for the period addressed
in such proceeding or subsequent periods; and
ii. No other ITCS, capacity assignments, revenue requirements, or
similar "stranded costs" or penalties should be shifted to
Northern California ratepayers or PG&E shareholders from
Southern California, as alleged in the PEPR/ITCS proceeding,
the SoCalGas BCAP (Application 96-03-031), and other
proceedings.
b. ITCS Account (Noncore portion)
------------------------------
PG&E will absorb 50 percent of the noncore portion of ITCS
charges as currently defined, less brokering revenues, plus
interest, from the inception of the ITCS account. PG&E's
liability is limited to 50 percent, and therefore, includes any
rate reduction approved by the CPUC in response to Advice Letter
1952-G
Consequently:
-65-
i. PG&E will not be responsible for any proposed additional
Northern California ITCS costs or other penalties or
remedies alleged in the PEPR/ITCS proceeding for the period
addressed in such proceeding or subsequent periods;
ii. No other ITCS, capacity assignments, revenue requirements,
or similar "stranded costs" or penalties should be shifted
to Northern California ratepayers or PG&E shareholders from
Southern California, as alleged in the PEPR/ITCS
proceeding, the SoCalGas BCAP (Application 96-03-031), and
other proceedings.
iii. PG&E shall be entitled to recovery of 50 percent of ITCS
charges through gas transportation rates. No ITCS charges
shall be recovered through electric rates except those paid
by PG&E's UEG as a noncore gas customer.
c. Pipeline Expansion Rates
------------------------
PG&E agrees that, for ratemaking purposes, the initial capital
cost of the PG&E portion of the PG&E/PGT Pipeline Expansion
Project will be $736 million. In recalculating rates using the
lower Line 401 capital costs, PG&E will use the Company's utility
corporate cost of capital and capital structure. The rates and
terms of service for the Malin to on- and off-system paths, which
include a Line 401 component, and the major assumptions used in
deriving the Line 401 component, are as specified in Sections
II.I and IV. The rates and terms of service for G-XF firm service
are as specified in Section II.B.1. Other options available to
firm Expansion shippers are described in Section II.F.1.c.
d. Backbone Credit
---------------
PG&E agrees not to collect in future rates the balance of the
Backbone Credit Memorandum Account. As of the date the Gas Accord
is approved by the CPUC, PG&E will not provide a backbone credit
to any shipper and will remove the backbone crediting provisions
from its tariffs. The Backbone Credit Memorandum Account will be
terminated as of the date the Gas Accord is approved.
5. EAD Contracts
-------------
(A.92-07-047, 92-07-049, 95-02-008, and 95-02-010) For the period
from the contracts' inception dates until the date the Gas Accord
rate structure is implemented, PG&E will collect 75 percent of EAD
revenue shortfalls by operation of the Noncore Fixed Cost Account.
This covers all EAD contracts, except those with Gaylord and Posco,
approved in Decisions 95-06-022 and 95-06-023, respectively. With
respect to those contracts, PG&E will be at risk for 100 percent of
EAD shortfall revenue. During the Gas Accord period, PG&E will not
collect any EAD revenue shortfalls in rates. The Commission will not
take any further action in and will close this consolidated
proceeding.
6. BCAP Phase II
-------------
-66-
(A.94-11-015)
In PG&E's 1995 BCAP, SMUD proposed an unbundled backbone transmission
rate. Decision 95-12-053, recognizing that there were issues that
needed to be addressed prior to adopting such a rate, established a
second phase in the BCAP. The Decision also recognized that these
issues could potentially be resolved in the Accord, and therefore
encouraged parties to enter into negotiations as part of the Accord
process. Subsequent to the issuance of Decision 95-12-053, PG&E and
SMUD have reached preliminary agreement for service that better meets
SMUD's needs, as discussed in Section II.F.6. Subject to timely
completing the definitive agreements and securing CPUC approval, this
arrangement will resolve SMUD's Phase II BCAP issues. The Gas Accord
provides the framework necessary for PG&E to negotiate to resolve any
remaining concerns of other parties.
7. Remaining Reasonableness Issues
-------------------------------
(A.93-04-011, 94-04-002, 95-04-002, and 96-04-001)
All core procurement cost recovery after May 1994 shall be in
accordance with PG&E's revised CPIM. All other issues outstanding in
reasonableness proceedings are deemed settled and no party shall seek
or recommend any disallowance, sanction, or penalty associated any
gas reasonableness issue, named or unnamed for years 1992 through
1995.
8. 1988 - 1990 Gas Reasonableness Issues
-------------------------------------
(A.91-04-003)
If the Gas Accord Settlement is finally adopted by the Commission, or
adopted with modifications acceptable to PG&E and DRA, PG&E will
permanently forego recovering from its ratepayers any of the
disallowance ordered by Decision 94-03-050, which has been (or will
be) refunded to ratepayers, notwithstanding the outcome of its
pending lawsuit in Federal District court (Civil No. C-94-4381 WHO).
In the event the Federal District Court issues a decision prior to a
Commission decision on the Gas Accord, PG&E will not execute any
court judgment or otherwise seek recovery of the disallowance and
associated refunds ordered as a result of Decision 94-03-050, unless
in PG&E's reasonable judgment, failure to do so would prejudice
PG&E's right to said recovery. In the event PG&E seeks recovery of a
refund in order to preserve its rights pending a Commission decision
on the Accord, PG&E agrees to once again refund the disallowance to
ratepayers upon final approval of the Gas Accord Settlement.
The UEG and noncore will receive their portion of the 1988-1990
disallowance ordered by Decision 94-03-050 upon approval of the
refund plan pending before the Commission. The UEG's portion of the
1988-1990 disallowance ordered by Decision 94-03-050 will be credited
directly to the ECAC balancing account and will not be refunded to
electric customers directly. This treatment will not have an effect
on PG&E's electric rate freeze, and will be subject to the same
provisions as other ECAC balances.
-67-
As part of the overall Gas Accord Settlement, the remaining phase III
C issues in Application 91-04-003 associated with the 1988-1990
disallowance (BCAP Phase II) are resolved for $3.7 million inclusive
of any interest through 1995. PG&E will credit its ECAC balancing
account $3.7 million effective December 31, 1995. Interest would
accrue from that date forward. This treatment will not have an effect
on PG&E's electric rate freeze, and will be subject to the same
provisions as other ECAC balances.
-68-
VI. VI. ACCORD RATES
TABLE 1
ILLUSTRATIVE RATE PROJECTIONS UNDER THE GAS ACCORD -- ON-SYSTEM
($/DTH)
1997 1998 1999 2000 2001 2002 AVG (1997-02)
Core (Bundled)
- ---------------------------
Residential 5.61 5.62 5.75 5.79 5.93 6.07 5.79
Small Commercial 5.65 5.66 5.80 5.83 5.97 6.11 5.84
Large Commercial 3.93 3.92 4.02 4.01 4.11 4.21 4.03
Noncore (Firm Topock)
- ---------------------------
Distribution 1.14 1.11 1.11 1.10 1.12 1.15 1.12
Transmission 0.48 0.45 0.43 0.40 0.41 0.42 0.43
UEG 0.42 0.39 0.38 0.36 0.36 0.37 0.38
COG 0.42 0.39 0.38 0.36 0.36 0.37 0.38
Coalinga 0.47 0.44 0.43 0.41 0.42 0.42 0.43
Palo Alto 0.42 0.40 0.38 0.36 0.37 0.38 0.39
Noncore (Firm Malin)
- ---------------------------
Distribution 1.23 1.21 1.21 1.20 1.22 1.24 1.22
Transmission 0.57 0.54 0.53 0.50 0.51 0.51 0.53
UEG 0.51 0.49 0.48 0.45 0.46 0.46 0.48
COG 0.51 0.49 0.48 0.45 0.46 0.46 0.48
Coalinga 0.56 0.54 0.53 0.51 0.51 0.52 0.53
Palo Alto 0.52 0.49 0.48 0.46 0.47 0.47 0.48
Noncore (Firm California Gas)
- ---------------------------
Distribution 1.10 1.06 1.06 1.04 1.07 1.09 1.07
Transmission 0.44 0.40 0.38 0.35 0.35 0.36 0.38
UEG 0.37 0.34 0.32 0.30 0.31 0.31 0.33
COG 0.37 0.34 0.32 0.30 0.31 0.31 0.33
Coalinga 0.43 0.39 0.37 0.35 0.36 0.37 0.38
Palo Alto 0.38 0.35 0.33 0.31 0.31 0.32 0.33
Notes:
a) Some portions of these rates are guaranteed.
b) Core rates are bundled and include average backbone transmission costs, local
transmission, distribution, storage, customer class charge, and a forecast of
procurement and interstate pipeline demand charges.
c) Noncore rates include backbone transmission, local transmission, customer
class charges, customer access charges and distribution charges.
-69-
TABLE 2
FIRM BACKBONE CHARGE -- ANNUAL RATES (AFT)
MFV RATE DESIGN
ON-SYSTEM DELIVERIES
1997 1998 1999 2000 2001 2002
Malin to On-System - Core
- -----------------------
Reservation Charge ($/Dth/mo) 2.20 2.23 2.27 2.32 2.36 2.41
Usage Charge ($/Dth) 0.041 0.042 0.043 0.043 0.044 0.045
Total ($/Dth@Full 0.113 0.115 0.118 0.119 0.122 0.124
Contract)
Malin to On-System
- -----------------------
Reservation Charge ($/Dth/mo) 3.95 4.21 4.43 4.52 4.61 4.69
Usage Charge ($/Dth) 0.108 0.114 0.119 0.118 0.117 0.115
Total ($/Dth@Full 0.238 0.253 0.265 0.267 0.269 0.269
Contract)
Topock to On-System
- -----------------------
Reservation Charge ($/Dth/mo) 3.16 3.45 3.69 3.81 3.86 3.91
Usage Charge ($/Dth) 0.041 0.042 0.043 0.044 0.045 0.046
Total ($/Dth@Full 0.145 0.155 0.164 0.169 0.172 0.175
Contract)
California Gas and On-System Storage to On-System
- -----------------------
Reservation Charge ($/Dth/mo) 2.00 2.11 2.20 2.26 2.29 2.33
Usage Charge ($/Dth) 0.036 0.038 0.039 0.039 0.039 0.039
Total ($/Dth@Full 0.102 0.107 0.111 0.113 0.114 0.116
Contract)
Notes:
a) These rates are only the backbone transmission charge component of the
transmission service. They exclude local transmission charges, customer class
charges, customer access charges, distribution charges, storage charges, and
shrinkage charges.
b) On-system backbone transmission charges are based on an 87.5% load factor.
c) The "Total" rows represent the average backbone transmission charge incurred
by a firm shipper that uses its full contract quantity at a 100% load factor.
d) Customers delivering gas to storage facilities pay the applicable backbone
transmission on-system rate from Malin, Topock or California production.
e) Core and core wholesale are assigned 606.5 MMcf/d (615.6 Mdth/d) of capacity
on Line 400 at vintaged rates. These rates are shown under "Malin to On-System -
Core". Any additional usage from Malin by core or core wholesale must be on the
"Malin to on-system path".
f) These rates are subject to change during the Accord period pursuant only to
the z-factor provisions of Section II.I.7. Malin to on-system charges include a
phase-in of Line 401 costs as described in Section II.I.3.
g) Gathering facilities are assumed to be fully depreciated by January 1, 1997.
Gathering O&M expenses are included as part of the common backbone component.
AFT continued next page
-70-
TABLE 3
FIRM BACKBONE TRANSPORTATION -- ANNUAL RATES (AFT)
SFV RATE DESIGN
ON-SYSTEM DELIVERIES
1997 1998 1999 2000 2001 2002
Malin to On-System Core
- ----------------------
Reservation Charge ($/Dth/mo) 3.19 3.24 3.30 3.37 3.44 3.52
Usage Charge ($/Dth) 0.008 0.008 0.009 0.009 0.009 0.009
Total ($/Dth@Full 0.113 0.115 0.117 0.120 0.122 0.125
Contract)
Malin to On-System
- ----------------------
Reservation Charge ($/Dth/mo) 7.01 7.48 7.83 7.90 7.95 7.96
Usage Charge ($/Dth) 0.007 0.007 0.007 0.007 0.007 0.007
Total ($/Dth@Full 0.237 0.253 0.264 0.267 0.268 0.269
Contract)
Topock to On-System
- ----------------------
Reservation Charge ($/Dth/mo) 4.31 4.63 4.89 5.03 5.11 5.19
Usage Charge ($/Dth) 0.004 0.004 0.004 0.004 0.004 0.004
Total ($/Dth@Full 0.146 0.156 0.165 0.169 0.172 0.175
Contract)
California Gas and On-System
Storage to On-System
- ----------------------
Reservation Charge ($/Dth/mo) 3.02 3.18 3.30 3.36 3.39 3.43
Usage Charge ($/Dth) 0.003 0.003 0.003 0.003 0.003 0.003
Total ($/Dth@Full 0.102 0.107 0.112 0.113 0.115 0.116
Contract)
Notes:
a) These rates are only the backbone transmission charge component of the
transmission service. They exclude local transmission charges, customer class
charges, customer access charges, distribution charges, storage charges, and
shrinkage charges.
b) On-system backbone transmission charges are based on an 87.5% load factor.
c) The "Total" rows represent the average backbone transmission charge incurred
by a firm shipper that uses its full contract quantity at a 100% load factor.
d) Customers delivering gas to storage facilities pay the applicable backbone
transmission on-system rate from Malin, Topock or California production.
e) Core and core wholesale are assigned 606.5 MMcf/d (615.6 Mdth/d) of capacity
on Line 400 at vintage rates. Any additional usage from Malin by core or core
wholesale must be on the Malin to on-system path.
f) These rates are subject to change during the Accord period pursuant only to
the z-factor provisions of Section II.I.7. Malin to on-system charges include a
phase-in of Line 401 costs as described in Section II.I.3.
g) Gathering facilities are assumed to be fully depreciated by January 1, 1997.
Gathering O&M expenses are included as part of the common backbone component.
-71-
TABLE 4
FIRM BACKBONE TRANSPORTATION CHARGES -- SEASONAL RATES (SFT)
MFV RATE DESIGN
ON-SYSTEM DELIVERIES
1997 1998 1999 2000 2001 2002
Malin to On-System
- ----------------------
Reservation Charge ($/Dth/mo) 4.74 5.06 5.31 5.43 5.53 5.63
Usage Charge ($/Dth) 0.129 0.137 0.143 0.142 0.140 0.138
Total ($/Dth@Full Contract) 0.285 0.303 0.318 0.320 0.322 0.323
Topock to On-System
- ----------------------
Reservation Charge ($/Dth/mo) 3.79 4.14 4.42 4.57 4.63 4.69
Usage Charge ($/Dth) 0.050 0.051 0.052 0.053 0.054 0.055
Total ($/Dth@Full Contract) 0.175 0.187 0.197 0.203 0.206 0.209
California Gas and On-System Storage to On-System
- ----------------------
Reservation Charge ($/Dth/mo) 2.40 2.53 2.64 2.71 2.75 2.79
Usage Charge ($/Dth) 0.044 0.046 0.047 0.047 0.047 0.047
Total ($/Dth@Full Contract) 0.123 0.129 0.134 0.136 0.137 0.139
Notes:
a) Firm Seasonal rates are 120% of Firm Annual rates.
b) These rates are only the backbone transmission charge component of the
transmission service. They exclude local transmission charges, customer class
charges, customer access charges, distribution charges, storage charges, and
shrinkage charges.
c) The "Total" rows represent the average backbone transmission cost incurred by
a firm shipper that uses its full contract quantity at a 100% load factor.
d) Customers delivering gas to storage facilities pay the applicable backbone
transmission on-system rate from Malin, Topock or California production.
e) These rates are subject to change during the Accord period pursuant only to
the z-factor provisions of Section II.I.7. Malin to on-system rates include
phase-in of Line 401 costs as described in Section II.I.3.
f) Gathering facilities are assumed to be fully depreciated by January 1, 1997.
Gathering O&M expenses are included as part of the common backbone component.
g) For the period July 1997 through March 1998, core will receive seasonal
service (SFT) from Topock at a rate that is 110% of annual firm rates (AFT).
SFT continued next page
-72-
TABLE 5
FIRM BACKBONE TRANSPORTATION CHARGES -- SEASONAL RATES (SFT)
SFV RATE DESIGN
ON-SYSTEM DELIVERIES
1997 1998 1999 2000 2001 2002
Malin to On-System
- ----------------------
Reservation Charge ($/Dth/mo) 8.41 8.97 9.39 9.48 9.53 9.55
Usage Charge ($/Dth) 0.008 0.008 0.008 0.009 0.009 0.009
Total ($/Dth@Full Contract) 0.285 0.303 0.317 0.321 0.322 0.323
Topock to On-System
- ----------------------
Reservation Charge ($/Dth/mo) 5.17 5.55 5.86 6.04 6.13 6.23
Usage Charge ($/Dth) 0.004 0.004 0.004 0.004 0.005 0.005
Total ($/Dth@Full Contract) 0.174 0.187 0.197 0.203 0.207 0.210
California Gas and On-System Storage
to On-System
- ----------------------
Reservation Charge ($/Dth/mo) 3.62 3.81 3.96 4.03 4.07 4.11
Usage Charge ($/Dth) 0.004 0.004 0.004 0.004 0.004 0.004
Total ($/Dth@Full Contract) 0.123 0.129 0.134 0.136 0.138 0.139
Notes:
a) Firm Seasonal rates are 120% of Firm Annual rates.
b) These rates are only the backbone transmission charge component of the
transmission service. They exclude local transmission charges, customer
class charges, customer access charges, distribution charges, storage
charges, and shrinkage charges.
c) The "Total" rows represent the average backbone transmission cost incurred
by a firm shipper that uses its full contract quantity at a 100% load
factor.
d) Customers delivering gas to storage facilities pay the applicable backbone
transmission on-system rate from Malin, Topock or California production.
e) These rates are subject to change during the Accord period pursuant only to
the z-factor provisions of Section II.I.7. Malin to on-system rates include
a phase-in of Line 401 costs described in Section II.I.3.
f) Gathering facilities are assumed to be fully depreciated by January 1, 1997.
Gathering O&M expenses are included as part of the common backbone
component.
g) For the period July 1997 through March 1998, core will receive seasonal
service (SFT) from Topock at a rate that is 110% of annual firm rates (AFT).
-73-
TABLE 6
AS-AVAILABLE BACKBONE TRANSPORTATION (AA)
ON-SYSTEM DELIVERIES
1997 1998 1998 1999 2000 2001 2002
1/1-3/31 4/1-12/31
Malin to On-System
- -----------------
Usage Charge ($/Dth) 0.261 0.278 0.303 0.317 0.320 0.322 0.323
Topock to On-System
- -----------------
Usage Charge ($/Dth) 0.160 0.171 0.187 0.197 0.203 0.206 0.209
California Gas to On-System
- -----------------
Usage Charge ($/Dth) 0.112 0.118 0.129 0.134 0.136 0.138 0.139
On-System Storage to On-System
- -----------------
Usage Charge ($/Dth) 0.000 0.000 0.000 0.000 0.000 0.000 0.000
Notes:
a) As-Available rates are 110% of Firm-Annual rates through March 31, 1998, and
120% thereafter.
b) These rates are only the backbone transmission charge component of the
transmission service. They exclude local transmission charges, customer class
charges, customer access charges, distribution charges, storage charges, and
shrinkage charges.
c) Customers delivering gas to storage facilities pay the applicable backbone
transmission on-system rate from Malin, Topock or California production.
d) Consistent with current CPUC rules, there will not be a transmission charge
for transmission from storage unless firm transmission capacity is required to
schedule the movement of the natural gas from the storage facility.
e) These rates are subject to change during the Accord period pursuant only to
the z-factor provisions of Section II.I.7. Malin to on-system rates include a
phase-in of Line 401 costs described in Section II.I.3.
f) Gathering facilities are assumed to be fully depreciated by January 1, 1997.
Gathering O&M expenses are included as part of the common backbone component.
-74-
TABLE 7
FIRM BACKBONE TRANSPORTATION CHARGES -- ANNUAL RATES (AFT-OFF)
MFV RATE DESIGN
OFF-SYSTEM DELIVERIES
1997 1998 1999 2000 2001 2002
Malin to Off-System
- ----------------------
Reservation Charge ($/Dth/mo) 5.52 5.46 5.39 5.32 5.25 5.18
Usage Charge ($/Dth) 0.216 0.205 0.195 0.185 0.175 0.165
Total ($/Dth@Full 0.397 0.384 0.372 0.360 0.348 0.335
Contract)
Topock to Off-System
- ----------------------
Reservation Charge ($/Dth/mo) 3.16 3.45 3.69 3.81 3.86 3.91
Usage Charge ($/Dth) 0.041 0.042 0.043 0.044 0.045 0.046
Total ($/Dth@Full 0.145 0.155 0.164 0.169 0.172 0.175
Contract)
California Gas and On-System Storage to Off-System
- ----------------------
Reservation Charge ($/Dth/mo) 5.52 5.46 5.39 5.32 5.25 5.18
Usage Charge ($/Dth) 0.216 0.205 0.195 0.185 0.175 0.165
Total ($/Dth@Full 0.397 0.384 0.372 0.360 0.348 0.335
Contract)
Notes:
a) These rates are only the backbone transmission charge component of the
transmission service. They exclude local transmission charges, customer class
charges, customer access charges, distribution charges, storage charges, and
shrinkage charges.
b) Except for Malin to off-system, and California gas to off-system, backbone
transmission rates are based on an 87.5% load factor.
c) The "Total" rows represent the average backbone transmission cost incurred by
a firm shipper that uses its full contract quantity at a 100% load factor.
d) Malin to off-system charges are based on Line 401's embedded costs and a 95%
load factor.
e) These rates are subject to change during the Accord period pursuant only to
the z-factor provisions of Section II.I.7.
f) Gathering facilities are assumed to be fully depreciated by January 1, 1997.
Gathering O&M expenses are included as part of the common backbone component.
g) California gas and storage to off-system are assumed to flow on Line 401, and
are priced at the Line 401 rate.
AFT-Off continued next page
-75-
TABLE 8
FIRM BACKBONE TRANSPORTATION CHARGES -- ANNUAL RATES (AFT-OFF)
SFV RATE DESIGN
OFF-SYSTEM DELIVERIES
1997 1998 1999 2000 2001 2002
Malin to Off-System
- ----------------------
Reservation Charge ($/Dth/mo) 11.66 11.28 10.91 10.55 10.19 9.83
Usage Charge ($/Dth) 0.004 0.004 0.004 0.004 0.004 0.004
Total ($/Dth@Full 0.387 0.375 0.363 0.351 0.339 0.327
Contract)
Topock to Off-System
- ----------------------
Reservation Charge ($/Dth/mo) 4.31 4.63 4.89 5.03 5.11 5.19
Usage Charge ($/Dth) 0.004 0.004 0.004 0.004 0.004 0.004
Total ($/Dth@Full 0.146 0.156 0.165 0.169 0.172 0.175
Contract)
California Gas and On-System Storage to
Off-System
- ----------------------
Reservation Charge ($/Dth/mo) 11.66 11.28 10.91 10.55 10.19 9.83
Usage Charge ($/Dth) 0.004 0.004 0.004 0.004 0.004 0.004
Total ($/Dth@Full 0.387 0.375 0.363 0.351 0.339 0.327
Contract)
Notes:
a) These rates are only the backbone transmission charge component of the
transmission service. They exclude local transmission charges, customer class
charges, customer access charges, distribution charges, storage charges, and
shrinkage charges.
b) Except for Malin to off-system, and California gas to off-system, backbone
transmission rates are based on an 87.5% load factor.
c) The "Total" rows represent the average backbone transmission cost incurred by
a firm shipper that uses its full contract quantity at a 100% load factor.
d) Malin to off-system charges are based on the embedded cost of Line 401 and a
95% load factor.
e) These rates are subject to change during the Accord period pursuant only to
the z-factor provisions of Section II.I.7.
f) Gathering facilities are assumed to be fully depreciated by January 1, 1997.
Gathering O&M expenses are included as part of the common backbone component.
g) California gas and storage to off-system are assumed to flow on Line 401, and
are priced at the Line 401 rate.
-76-
TABLE 9
AS-AVAILABLE BACKBONE TRANSPORTATION (AA-OFF)
OFF-SYSTEM DELIVERIES
1997 1998 1998 1999 2000 2001 2002
1/1-3/31 4/1-12/31
Malin to Off-System
- -----------------
Usage Charge ($/Dth) 0.437 0.424 0.462 0.447 0.433 0.418 0.403
Topock to Off-System
- -----------------
Usage Charge ($/Dth) 0.160 0.171 0.187 0.197 0.203 0.206 0.209
California Gas and On-System
Storage to Off-System
- -----------------
Usage Charge ($/Dth) 0.437 0.424 0.462 0.447 0.433 0.418 0.403
Notes:
a) These rates are only the backbone transmission charge component of the
transmission service. They exclude local transmission charges, customer class
charges, customer access charges, distribution charges, storage charges, and
shrinkage charges.
b) As-Available rates are 110% of Firm-Annual rates through March 31, 1998, and
120% thereafter.
c) Gathering facilities are assumed to be fully depreciated by January 1, 1997.
Gathering O&M expenses are included as part of the common backbone component.
d) California gas and storage to off-system is assumed to flow on Line 401, and
is priced at the Line 401 rate.
-77-
TABLE 10
FIRM TRANSPORTATION -- EXPANSION SHIPPERS -- ANNUAL RATES (G-XF)
MFV RATE DESIGN
OFF-SYSTEM DELIVERIES
1997 1998 1999 2000 2001 2002
Malin to Off-System
- ----------------------
Reservation Charge ($/Dth/mo) 5.52 5.46 5.39 5.32 5.25 5.18
Usage Charge ($/Dth) 0.216 0.205 0.195 0.185 0.175 0.165
Total ($/Dth@Full 0.397 0.384 0.372 0.360 0.348 0.335
Contract)
Notes:
a) These rates are only the backbone transmission charge component of the
transmission service. They exclude local transmission charges, customer class
charges, customer access charges, distribution charges, storage charges, and
shrinkage charges.
b) The "Total" rows represent the average backbone transmission cost incurred by
a firm shipper that uses its full contract quantity at a 100% load factor.
c) G-XF charges are based on the embedded cost of Line 401 and a 95% load
factor.
d) These rates are subject to change during the Accord period pursuant only to
the z-factor provisions of Section II.I.7.
-78-
TABLE 11
FIRM TRANSPORTATION -- EXPANSION SHIPPERS -- ANNUAL RATES (G-XF)
SFV RATE DESIGN
OFF-SYSTEM DELIVERIES
1997 1998 1999 2000 2001 2002
Malin to Off-System
- ----------------------
Reservation Charge ($/Dth/mo) 11.66 11.28 10.91 10.55 10.19 9.83
Usage Charge ($/Dth) 0.004 0.004 0.004 0.004 0.004 0.004
Total ($/Dth@Full 0.387 0.375 0.363 0.351 0.339 0.327
Contract)
Notes:
a) These rates are only the backbone transmission charge component of the
transmission service. They exclude local transmission charges, customer class
charges, customer access charges, distribution charges, storage charges, and
shrinkage charges.
b) The "Total" rows represent the average backbone transmission cost incurred by
a firm shipper that uses its full contract quantity at a 100% load factor.
c) G-XF charges are based on the embedded cost of Line 401 and a 95% load
factor.
d) These rates are subject to change during the Accord period pursuant only to
the z-factor provisions of Section II.I.7.
-79-
TABLE 12
STORAGE RATES
FIRM STORAGE SERVICE (FS) CAPACITY Withdrawal
------------- -----------------
RESERVATION CHARGES
Annual Reservation Charge $0.746/Dth $9.651/Dth/day
VARIABLE CHARGES
Variable Charge $0.039/Dth $0.039/Dth
NEGOTIATED FIRM STORAGE (NFS) INJECTION INVENTORY Withdrawal
------------- ------------ ---------------
MAXIMUM RATE
Volumetric Rate 8.149/Dth $1.144/Dth $4.923/Dth
NEGOTIATED AS-AVAILABLE STORAGE (NAS)
MAXIMUM RATE
Volumetric Rate $8.149/Dth $4.923/Dth
Notes:
a) Rates for storage services are based on the costs of storage injection,
inventory and withdrawal.
b) Firm Storage rates are subfunctionalized by a capacity (combined injection
and inventory) charge and withdrawal charge. The capacity charge is calculated
assuming recovery of both the injection and inventory revenue requirement over
the annual inventory design capacity allocated to the unbundled storage program.
The withdrawal charge is calculated based on recovery of the withdrawal revenue
requirement over the daily withdrawal design capacity allocated to the unbundled
storage program.
c) Firm Storage capacity and withdrawal charges are recovered through a
reservation (fixed) and volumetric (variable) component.
d) Negotiated Firm rates may be one-part rates (volumetric) or two-part rates
(reservation and variable), as negotiated between parties. The volumetric
equivalent is shown above.
e) Negotiated As-available Storage Injection and Withdrawal rates are recovered
through a volumetric charge only.
f) The flexibility inherent in this storage offer could result in stranded
facilities and PG&E requires the opportunity to collect the value of the storage
services. Negotiated rates (NFS and NAS) are capped at the price which will
collect 100 percent of PG&E's total revenue requirement for the unbundled
storage program under all three subfunctions (e.g. inventory, injection, or
withdrawal.) The maximum rates are based on a rate design assuming an average
injection period of 30 days and an average withdrawal period of 7 days.
g) Negotiated Firm and As-available services are negotiable above a price floor
representing PG&E's marginal cost of providing the service.
h) Rates will be implemented for the unbundled storage program in April 1,1998.
i) The maximum annual charge for parking and lending is based on the annual cost
of cycling one Dth of Firm Storage Gas assuming the full 214 day injection
season and 151 day withdrawal season. The annual cycle cost is $0.89 per Dth.
-80-
TABLE 13
LOCAL TRANSMISSION RATES
($/DTH)
1997 1998 1999 2000 2001 2002
Core .254 .260 .267 .273 .280 .287
Noncore .131 .135 .138 .141 .145 .149
Notes:
a) These rates are subject to change during the Accord period pursuant only to
the z-factor provisions of Section II.I.7.
b) Rates for 1998-2002 escalate at 2.5 percent.
c) First year rates are based on 1996 GRC revenue requirement, 1995 BCAP cost
allocation and throughput, and 57.8% of BCAP adopted APD adjustment.
-81-
TABLE 14
ILLUSTRATIVE CUSTOMER CLASS CHARGES
($/DTH)
1997 1998 1999 2000 2001 2002
Residential .353 .224 .223 .121 .119 .118
Small Commercial .404 .276 .276 .174 .175 .175
Large Commercial .300 .200 .201 .099 .099 .100
Industrial
Distribution .207 .149 .122 .083 .084 .085
Industrial
Transmission .174 .127 .100 .061 .062 .062
UEG .132 .093 .066 .039 .039 .039
Cogeneration .132 .093 .066 .039 .039 .039
Wholesale
Coalinga .145 .100 .072 .045 .045 .045
Palo Alto .136 .094 .066 .039 .039 .039
Notes:
a) Customer class charges include no ITCS for core, and 50% of ITCS for noncore,
as described in Section IV.B.4. Core rates include a refund of ITCS costs
recovered prior to 1997.
b) Rates for 1997 consistent with 1995 BCAP decision. Rates for 1998-2002 do not
escalate at 2.5%. Instead they represent forecasts of individual balancing
accounts. Actual rates will be determined in BCAPs or successor proceedings.
c) The UEG and cogeneration customer class charges include costs associated with
cogeneration rate parity. See section III.C.5.
-82-
TABLE 15 (REVISED--9/11/96)
1997 CUSTOMER ACCESS CHARGE
FOR ON-SYSTEM CUSTOMERS DIRECTLY CONNECTED
TO THE TRANSMISSION SYSTEM
($/MONTH)
1997 1998 1999 2000 2001 2002
Industrial (Therms/Month)
- ------------
10.49 10.75 11.02 11.30 11.58 11.87
Tier 1 0 to 5,000
82.66 84.73 86.84 89.02 91.24 93.52
Tier 2 5,001 to 10,000
313.58 321.42 329.45 337.69 346.13 354.79
Tier 3 10,001 to 50,000
826.61 847.28 868.46 890.17 912.42 935.23
Tier 4 50,001 to 200,000
1,183.50 1,213.09 1,243.41 1,274.50 1,306.36 1,339.02
Tier 5 200,001 to 1,000,000
3,440.30 3,526.31 3,614.47 3,704.83 3,797.45 3,892.38
Tier 6 1,000,001 and above
113,083 115,910 118,808 121,778 124,822 127,943
UEG
Cogeneration ($/Dth) .00710 .00728 .00746 .00765 .00784 .00803
WHOLESALE
- ------------
908.67 931.39 954.67 978.54 1,003.00 1,028.08
Coalinga
3,882.42 3, 979.48 4,078.96 4,180.94 4,285.46 4,392.60
Palo Alto
Notes:
a) Customer access charges escalate at 2.5% per year.
-83-
TABLE 16
FORECAST DISTRIBUTION RATES
($/DTH)
1997 1998 1999 2000 2001 2002
Residential 2.53 2.59 2.66 2.72 2.79 2.86
Small Commercial 2.53 2.59 2.66 2.72 2.79 2.86
Large Commercial .94 .96 .99 1.01 1.04 1.06
Industrial .656 .672 .689 .706 .724 .742
Distribution
Notes:
a) Core and noncore rates are distribution only.
b) Commercial and industrial rates shown are average distribution rates.
Commercial and industrial distribution rates will be seasonally differentiated
and include a monthly customer charge.
c) Illustrative rates, based on 2.5% escalation, are shown. Actual rates will be
determined in BCAPs or successor proceedings.
d) There is no cogeneration rate shown, since cogenerators receive rate parity
with UEG, which is transmission level service.
e) All rates exclude procurement and interstate transmission.
-84-
TABLE 17
ILLUSTRATIVE BUNDLED
1997 CORE TRANSPORTATION RATES
($/DTH)
LARGE
RESIDENTIAL SMALL COMMERCIAL COMMERCIAL AVERAGE CORE
Intrastate Backbone .148 .148 .130 .147
Transmission
Intrastate Local .254 .254 .254 .254
Transmission
Customer class charge .353 .404 .300 .363
Distribution 2.53 2.53 .945 2.45
Storage .115 .115 .102 .115
Procurement 1.92 1.92 1.92 1.92
Interstate Transmission .292 .281 .281 .289
-------------------------------------------------------------------------------------
Total 5.61 5.65 3.93 5.53
Note:
a) Average backbone transmission rate based on expected core deliveries from
Line 400, Line 300 and California gas production, based on the capacity
assignments discussed in Section I.E.
b) Average core storage rates are based on core capacity reservations set forth
in Section II.E.
-85-
TABLE 18 (REVISED--9/11/96)
1997 SEASONAL VOLUMETRIC RATES FOR DISTRIBUTION SERVICE CUSTOMERS
($/th)
SUMMER VOLUMETRIC WINTER AVERAGE WINTER TO
RATE VOLUMETRIC RATE VOLUMETRIC RATE SUMMER RATIO
Small Commercial $.166 $.250 $.212 1.50
Large Commercial $.065 $.110 $.089 1.70
Industrial $.048 $.064 $.056 1.35
Distribution
Notes:
a) Rates exclude monthly customer charge.
-86-