EXHIBIT 10
CPUC Promising Gas Options
OII 99=07=003
Operational Flow Order (OFO)
Settlement Agreement
October 20, 1999
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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
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Rules of Evidence, and Section 1152 of the California Evidence Code
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CPUC Promising Gas Options OII ▇▇-▇▇-▇▇▇
Operational Flow Order (OFO) Settlement Agreement
TABLE OF CONTENTS
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A. Introduction.......................................................... 1
B. Forum for Resolving Future Balancing Issues........................... 3
C. Provisions Designed to Reduce the Number and to Increase the
Predictability of OFOs................................................ 4
1. Operational Information........................................... 4
2. Pipeline Inventory Limits......................................... 6
3. Customer-Specific OFOs............................................ 7
4. Cashout Prices.................................................... 9
5. Core Procurement Group Imbalances................................. 10
6. Storage Allocation to Balancing................................... 11
D. Provisions Designed to Reduce the Impact of OFOs...................... 12
1. OFO Notification.................................................. 12
2. Noncompliance Charges During an OFO............................... 12
3. OFO Noncompliance Charge Exemption................................ 13
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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
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Rules of Evidence, and Section 1152 of the California Evidence Code
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Operational Flow Order (OFO) Settlement Agreement
A. Introduction
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The purpose of this OFO Settlement Agreement (Agreement, Settlement, or
Settlement Agreement) is to revise Pacific Gas and Electric Company's
(PG&E's) operating guidelines and gas tariffs to achieve the following
goals:
. Improve market access to operational information necessary for the
management of gas imbalances on PG&E's system.
. Significantly reduce the number of system-wide OFOs on the PG&E system.
. Reduce the impact of OFOs on the market.
. Revise certain procedures implemented under the Gas Accord, in order to
improve system operating efficiency, to clarify criteria used by PG&E in
making operational decisions, and to enhance customer interfaces with
PG&E's gas operations.
. Improve the transparency of operations to improve upon operational
signals to the market.
. Improve the ability of the market to foresee OFO events.
. Maintain the OFO process as both a signal and an incentive to the market
to balance supply and demand.
This Agreement is entered into by the Settlement Parties, as identified by
their attached signatures. This Agreement shall become effective on the
first day of the month following the thirtieth day after the date of a
California Public Utilities Commission ("CPUC" or "Commission") order
approving the OFO Settlement Agreement and shall continue in effect through
December 31, 2002.
On March 1, 1998, the Northern California natural gas market experienced a
dramatic change with the restructuring of services on the PG&E system under
a broadly-based settlement known as the "Gas Accord". Many
previously-bundled PG&E services were unbundled, providing more choice to
marketers, shippers, and end-use customers. PG&E and the Gas Accord
settling parties worked to develop the rules and guidelines to operate
PG&E's system under the Gas Accord provisions, including the unbundling of
pipeline transmission and storage services within Northern California. The
Gas Accord is effective through December 31, 2002.
Experience under the Gas Accord has indicated that certain adjustments are
appropriate, particularly with regard to customer balancing requirements
and charges; to issuance of
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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
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Rules of Evidence, and Section 1152 of the California Evidence Code
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OFOs; to whether OFOs are issued on a system-wide or customer-specific
basis; and to the operational information provided to the market and to
individual shippers.
This Agreement represents a settlement on these issues set forth herein in
the context of the natural gas strategy (D.99-07-015and I.99-07-003) of the
CPUC. Not all of the provisions agreed to herein require tariff changes,
and some provisions have already been implemented. Nevertheless, it is
important and appropriate to document here all issues where parties have
agreed to changes in operating guidelines and procedures.
This Agreement does not change the basic principles and structure of the
Gas Accord as agreed to by the settling parties to the Gas Accord and as
approved by the Commission in Decision ▇▇-▇▇-▇▇▇. The operating guideline
and gas tariff changes included within this Agreement, and made a part
hereof, are intended to modify certain limited implementation parameters of
the Gas Accord, and the Settlement Parties agree that such revisions are
within the original bounds of the Gas Accord structure.
This Agreement is a negotiated compromise of operational issues and is
broadly supported by parties who are marketers, shippers, wholesale and
retail end-use customers, and regulatory representatives. Nothing contained
herein shall be deemed to constitute an admission or an acceptance by any
party of any fact, principle, or position contained herein, except to the
extent that Settlement Parties, by signing this Agreement, acknowledge that
they pledge support for Commission approval and subsequent implementation
of these provisions.
This Agreement is to be treated as a complete package and not as a
collection of separate agreements on discrete issues or proceedings. To
accommodate the interests of different parties on diverse issues, the
Settlement Parties acknowledge that changes, concessions, or compromises by
a party or parties in one section of this Agreement necessitated changes,
concessions, or compromises by other parties in other sections.
This Agreement is intended to quickly resolve specific operating issues.
Decision ▇▇-▇▇-▇▇▇ in R.▇▇-▇▇-▇▇▇ contains additional proposals or issues
related to utility balancing services, imbalance trading, real-time
customer usage data, electronic bulletin boards, and other areas. PG&E and
the parties are pursuing or intend to pursue settlement discussions of
these additional issues. New settlement(s) may result in modifications to
some of the provisions contained in this Agreement.
As this OFO Settlement simply modifies the implementation of existing
operating parameters, PG&E will not seek to recover any costs associated
with implementing the provisions of this Settlement Agreement, except under
the provisions of Section B, below. This agreement on cost recovery is not
a precedent with respect to other settlements, litigation or regulatory
cases.
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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
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Rules of Evidence, and Section 1152 of the California Evidence Code
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B. Forum for Resolving Future Balancing Issues
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1. The Settlement Parties intend that the provisions contained in this
settlement will significantly reduce the number of system-wide OFOs on
PG&E's system. The Settlement Parties, through the Gas OFO Forum,
intend to monitor the effectiveness of the Settlement measures in
reducing the number of OFOs and to address on an ongoing basis,
improvements and/or modifications to PG&E's balancing and OFO
procedures. Any interested shipper or customer on the PG&E transmission
system who may be subject to OFOs may choose to participate in this
Forum.
2. If, six months after the effective date of this Settlement, there has
not been at least a twenty-five (25) percent reduction in the number of
system-wide OFOs during this first six-month period compared to the
same period in the prior year(s), PG&E in its next quarterly OFO report
(see Section C.1.f), will provide an analysis of why the number of OFOs
has not been reduced and propose additional measures to reduce the
number of system-wide OFOs in addition to those measures outlined in
this OFO Settlement Agreement. PG&E and the other members of the Forum
will consider in good faith whether, and how, PG&E's proposed
additional measures, as well as any other proposals suggested by other
Forum members, should be adopted.
3. The Gas OFO Forum will further explore the following issues:
a. The effectiveness of customer-specific OFOs and possible
improvements to the procedure outlined in this Settlement,
including the need and methodology for changes to the Performance
Factor set forth in Section C.3.b.(7).
b. Whether and how parties who significantly contribute to system-wide
OFOs on a repeated basis, e.g. to three (3) or more per month,
should be specifically identified. A "significant contributor" is
defined as any balancing entity with total imbalances greater than
5,000 Dth and 10 percent of its usage in the three days leading up
to each system-wide or customer-specific OFO. For Core Procurement
Groups, supply will be compared to their Determined Usage, which is
the Cumulative Imbalance (except for OFO days when the 24-hour
forecast will be used).
c. Whether the exemption for OFO noncompliance charges set forth in
Section D.3.b should be increased.
d. The need for the allocation of additional storage to balancing (see
Section C.6).
e. Changing the Cash-out procedures.
f. Other issues which relate to PG&E pipeline balancing and OFOs.
4. PG&E may seek recovery of implementation costs to provide additional
information or implement additional procedures which are recommended by
the Forum. Estimates of these costs will be provided to the Forum for
discussion prior to PG&E filing for recovery. PG&E may seek such
recovery and/or establishment of a balancing or memorandum account for
these projected costs prior to implementing the recommendation. Other
parties to this Settlement do not necessarily support PG&E's right to
recover these implementation costs.
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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
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Rules of Evidence, and Section 1152 of the California Evidence Code
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C. Provisions Designed to Reduce the Number and to Increase the Predictability
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of OFOs
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1. Operational Information
a. PG&E will provide the following daily operational information on
its Pipe Ranger Web site.
(1) Composite system temperature
(2) System demand
(3) Off-system deliveries by delivery point
(4) Fuel and lost and unaccounted for (LUAF) gas
(5) Storage injection by storage operator
(6) Total system demand (sum of items 2, 3, 4, & 5 above)
(7) Interconnect supply by receipt point
(8) Storage withdrawal by storage operator
(9) Total system supply (sum of items 7 & 8 above)
(10) Pipeline inventory change (supply minus demand, item 9 -
item 6)
(11) Beginning and ending pipeline
(12) Pipeline inventory lower and upper operating limits (as
established in this agreement)
(13) Difference between ending pipeline inventory and operating
limits
(14) Operational flow order (OFO), emergency flow order (EFO) and
involuntary diversion status
(15) Storage activity by injection and withdrawal, not just net
activity
(16) Storage injection and withdrawal used for pipeline balancing
(17) On-system supply
b. Forecast information specified in C.1.a, above, will be provided
for the current day and the next three days. This forecast is
updated approximately five times per day. PG&E will establish
specific not-later-than times of the day when the updates will
occur. If for some reason the data is not available by this time,
PG&E will place a notice on its Pipe Ranger Web site indicating
when the forecast data will be available.
c. Historical data will be provided for the prior two weeks.
d. Additionally, PG&E will provide on its Pipe Ranger Web site:
(1) Maximum pipeline capacity by path.
(2) Maximum daily pipeline capacity at interconnection points
for current day and next day.
(3) Monthly demand forecast by customer class.
(4) Daily storage inventory level for pipeline balancing as part
of the three-day historical data (updated monthly to reflect
cashouts and other adjustments).
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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
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(5) Current month imbalance gas in storage.
(6) Receipt point allocation and end-user curtailment
quantities for the system when pipeline operational
conditions requires allocations (trimming for balancing
purposes) or end-user curtailment. Customer-specific data
will only be provided to that customer or their designated
agent.
(7) Daily demand by customer class using the "24-hour forecast"
with a three-day posting lag.
(8) Daily demand by customer class using the day-after forecast
with a three-day posting lag.
(9) Balance of cash-in/out gas in storage and prior month
imbalances not cleared on a monthly basis.
(10) Cumulative sum of the changes in pipeline inventory (line
pack).
e. PG&E will maintain records of daily injection and withdrawal and
daily storage inventory levels for all storage accounts.
f. PG&E will post a quarterly OFO report on its Pipe Ranger Web site
pertaining to the number and causes of each customer-specific and
system-wide OFO, EFO, and "trimming" occasion ("Event") within the
prior three (3) months. PG&E will post this report within 30 days
after the close of the calendar quarter. The first OFO report may
cover less than three months of operation under this Agreement.
These quarterly OFO reports will show the sources of system
imbalance for each of the three (3) days prior to an Event, as
follows:
1) Imbalance and gas scheduled for each entity responsible for
managing imbalances as specified in C.3.b.(3). For Core
Procurement Groups, the supply will be compared to their
Determined Usage, which is their Cumulative Imbalance
(except for OFO days when the 24-hour forecast will be
used). Each such entity will be identified by a new and
unique numerical identifier, and not by name.
2) Pipeline imbalances.
3) Net market center imbalances for the aggregate of parking,
lending and storage services.
4) Pipeline balancing provided by allocated storage.
5) Beginning, ending and change in pipeline inventory.
6) Any proposed changes to any OFO and balancing procedures
and/or methodology addressed in this Settlement.
g. The Settlement Parties agree that for a period continuing until
twelve (12) months after the date this Settlement is filed with the
CPUC, the operational information provided herein is the
information needed for the market to analyze the status of PG&E's
pipeline balancing service and to anticipate OFOs. During this
period, PG&E need not provide additional data relevant to OFOs,
except as referenced in Section B.3.b or as agreed to by PG&E and
the other Settlement Parties. After this 12 month period, the other
Settlement Parties reserve their rights to bring to PG&E
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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
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Rules of Evidence, and Section 1152 of the California Evidence Code
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requests for further information, and PG&E agrees to engage in good
faith efforts to resolve such requests. The limitation on
information contained in this section does not limit, in any
manner, information requests pertaining to other matters, e.g.
electronic bulletin boards, imbalance trading, curtailments (local
or system-wide), secondary markets, capacity rights, and/or any
other issue contained in I.▇▇-▇▇-▇▇▇ or a separate CPUC proceeding.
h. No tariff changes are needed to revise the operational information
provided.
2. Pipeline Inventory Limits
a. PG&E will adjust its current procedures for determining when an OFO
is needed and for issuing an OFO. PG&E will issue an OFO for a Gas
Day if, on the day prior to this Gas Day, PG&E's forecast of
pipeline inventory for the Gas Day is either below the Lower
Pipeline Inventory Limit or above the Upper Pipeline Inventory
Limit, as provided in Sections C.2.c through f below. PG&E will
continue its current practice of determining the need for and
issuing of an OFO by 7:30 a.m. on the day before the Gas Day, or as
soon as possible thereafter. This practice is intended to allow
parties whose imbalances exceed the OFO tolerance band to use all
four nomination cycles, as specified in Gas Rule 21, Section B.3.d,
to make supply adjustments and avoid or reduce noncompliance
charges. Situations may still occur when an OFO needs to be issued
later in the day prior to Gas Day as is allowed by Gas Rule 14,
Section E.
b. The Lower and Upper Pipeline Inventory Limits are the levels below
and above which the safety and reliability of pipeline operations
are in jeopardy. These Limits replace the desired target inventory
levels and the range of 200 MMcf/d above and the 150 MMcf/d below
as currently specified in Gas Rule 14. This change allows the
pipeline to operate to the operational limits each day, without
anticipating trends in what suppliers schedule relative to market
demand.
c. The Lower and Upper Pipeline Inventory Limits will change, as
specified in Section C.2.d, below, depending on whether the
forecast of total system demand (the sum of on-system demand and
off-system deliveries) is "Low" or "High". The reason for the
change in the Pipeline Inventory Lower Limit is that under low
system demand, the required minimum pressures on the system can be
maintained at a lower pipeline inventory level. Higher demand
levels require higher pipeline inventories to maintain system
minimum pressures. The Upper Pipeline Inventory Limit is set to
allow for variations in supply or usage forecasts. Under low system
demand conditions, the potential is greater that forecast
variations must be absorbed by the pipeline inventory; therefore,
the Upper Pipeline Inventory Limit is set lower to allow for this
greater variability without jeopardizing operations. Under higher
system demand conditions, forecast variations are often managed by
supply or storage withdrawal adjustments, so the Upper Pipeline
Inventory Limit can be set higher.
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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
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Rules of Evidence, and Section 1152 of the California Evidence Code
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d. The Pipeline Inventory Limits used to determine OFOs are:
Pipeline Inventory Limits, MMcf
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Total Demand Forecast, MMcf Lower Upper
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Low Demand: 1,500 to 2,800 3,900 4,500
High Demand: 2,800 to 3,900 4,000 4,600
e. PG&E may elect not to issue an OFO for a Gas Day if the forecast of
pipeline inventory for the day following that Gas Day indicates the
pipeline inventory will return to within the Pipeline Inventory
Limits without the assistance of an OFO.
f. The Lower and Upper Pipeline Inventory Limits in effect each day
will be shown in the pipeline inventory report on the Pipe Ranger
Web site.
g. PG&E may revise these Pipeline Inventory Limits beyond those
specified in the table in Section C.2.d above. Any such revisions
will be established to ensure pipeline safety and reliability.
(1) Changes in the Pipeline Inventory Limits which are needed to
reflect operating conditions or limitations, including force
majeure events, can be implemented immediately as those
conditions warrant. PG&E will post these changes on its Pipe
Ranger Web site along with an explanation of the operational
limitation.
(2) Pipeline Inventory Limits may also change due to more
predictable factors. These include changes in end-user
demands, compressor operating conditions, pipeline and
compressor maintenance activities, and other operational
inputs which are used to determine the physical operating
limits of the pipeline. PG&E will post these changes on its
Pipe Ranger Web site at least two weeks before implementation,
along with a supporting explanation.
(3) If PG&E proposes to change the methodology used to decide when
to issue OFOs, PG&E will seek approval of such modifications
from the Gas OFO Forum before making this change.
3. Customer-Specific OFOs
a. PG&E's Gas Rule 14, Section E, currently provides for
customer-specific OFOs to be issued. Since April 1, 1998, PG&E has
issued several customer-specific OFOs when it was clear that a
limited number of large customer imbalances were the main
contributors to the system imbalance. To be more effective, a
better definition of the guidelines for issuing customer-specific,
or targeted, OFOs is needed.
b. PG&E will use the following process and criteria to determine when
to issue customer-specific OFOs, rather than a system-wide OFO, and
to determine which balancing entities are subject to the
customer-specific OFO.
(1) PG&E determines whether an OFO is needed for a Gas Day, as
described in Section C.2, Pipeline Inventory Limits.
(2) If an OFO needs to be issued, the on-system imbalance is
estimated for that OFO Day as the difference between the
forecast on-system supply and on-system demand. A portion of
this imbalance can be accommodated by (i) the
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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
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Rules of Evidence, and Section 1152 of the California Evidence Code
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amount of pipeline inventory available within the Pipeline
Inventory Limits, plus (ii) the storage injection or
withdrawal capacity available for system load balancing. This
portion of the imbalance that can be accommodated is divided
by the forecast on-system demand to determine the OFO
Tolerance Band (set as a percentage of usage). The remaining
imbalance is the volume of needed supply and/or demand relief
for the pipeline to stay within its Inventory Limits.
(3) Next, PG&E prepares an internal imbalance report forecasting
the OFO Day imbalance for each entity responsible for managing
imbalances. These "balancing entities" are: (a) Noncore
Balancing Aggregation Agreement (NBAA) agents; (b) Core
Procurement Groups (CPGs); and (c) Individual end-users who do
not have an NBAA agent.
(4) These balancing entity forecasts are composed of the same
individual end-use customer demand forecasts that are used to
forecast OFO compliance on INSIDEtracc. No change is proposed
in these methods.
(5) PG&E then reviews the internal imbalance report and identifies
those balancing entities with forecast imbalances exceeding
both the calculated OFO Tolerance Band percentage and an
imbalance volume of 5,000 Dth.
(6) Customer-specific OFOs will be issued, if (i) there are no
more than 10 balancing entities, and (ii) the total forecast
imbalance relief they would provide in aggregate, multiplied
by a Performance Factor, exceeds the volume relief needed for
the pipeline, as calculated in Section C.3.b.(2), above.
(7) The customer-specific OFO Performance Factor is a measure of
the historic effectiveness of these OFOs. Experience shows
that balancing entities issued an OFO may trade gas to get
within the tolerance band. However, such traded gas is still
on the system and does not help offset pipeline inventory
levels, since there is usually not an accompanying change in
demand under these circumstances. Therefore, the resulting
pipeline inventory relief provided may be less than forecast.
The Performance Factor is the system relief actually achieved
by customer-specific OFOs divided by the forecast relief
calculated per Section C.3.b.(6) above. Adjustments may be
made to the calculation to reflect experience over several
customer-specific OFOs and to normalize for such factors as
temperature differences between the forecast and actual data.
The Performance Factor may differ depending on whether it is a
high or low inventory OFO situation. The Performance Factor is
set initially at 100% for both high and low inventory
conditions. PG&E may adjust the Performance Factor. The
Performance Factor will not be adjusted to a percentage which
is less than the average of the actual performance for all
customer-specific OFOs since the effective date of this
Settlement. However, unless required by operational
conditions, PG&E will not reduce the Performance Factor below
50% without the prior consent of the Forum. PG&E will post the
changes to the Performance Factor, along with supporting data
and explanation within 14 days of each customer-specific OFO.
If a customer-specific OFO is issued within this 14-day
period, the Performance Factor currently in effect will be
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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
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Rules of Evidence, and Section 1152 of the California Evidence Code
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used. This information will be evaluated by the Gas OFO Forum
on an ongoing basis.
(8) In the event the conditions of Section C.3.b.(6) are not met,
a system-wide OFO will be issued.
(9) On occasion, even if the conditions of Section C.3.b.(6) are
met, operating experience or market conditions may indicate to
PG&E that customer-specific OFOs will not be effective in
achieving needed pipeline inventory relief. In these
instances, a system-wide OFO will be issued. If the conditions
of Section C.3.b.(6) are met, yet PG&E calls a system-wide
OFO, PG&E will post an explanation of the factors causing PG&E
to determine not to call a customer-specific OFO on its Pipe
Ranger Web site, and will include such information in its
quarterly OFO reports.
c. PG&E will post a general market notification of customer-specific
OFOs on its Pipe Ranger Web site by 7:30 a.m. PT on the day before
Gas Day, or as soon as possible thereafter, and will notify the
affected balancing entities by 8:00 a.m. PT, or as soon as possible
thereafter.
d. No tariff revisions are needed to reflect the operating guidelines
set forth above for issuing customer-specific OFOs.
4. Cashout Prices
a. The Gas Accord Settlement provides that: "The intent of imbalance
cashouts is to create an economic disincentive for incurring
cashout imbalances. PG&E will file to revise the imbalance charges
and cashout options if the Gas Accord provisions do not accomplish
this." (D.▇▇-▇▇-▇▇▇, Appendix 1, E.13.d.vii, page 26) At least
three times since the beginning of the Gas Accord, the
underdelivery cashout price was lower than the spot price,
providing the market with an incentive to cash-out rather than
avoiding or trading imbalances. This has occurred only for Tier I
commodity cashouts where the cashout price is either 95% or 105% of
the weighted market price. In these cases, certain marketers
arbitraged this cashout price by buying the gas from PG&E as
provided in Schedule G-BAL.
b. The commodity cashout price will be changed for Tier I Cashouts in
Schedule G-BAL to 75% (from 95%) of the Weighted Overdelivery Index
and to 125% (from 105%) of the Weighted Underdelivery Index.
c. Commodity cashout transactions will continue to be recorded in the
Balancing Charge Account (BCA).
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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
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Rules of Evidence, and Section 1152 of the California Evidence Code
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5. Core Procurement Group Imbalances
a. Core Procurement Groups (CPGs), which include PG&E's Core
Procurement Department, serve residential and small commercial
customers whose meters do not generally provide daily usage data.
Their cumulative usage over a "cycle" period is read at the meter
and recorded in a PG&E data base. They are also billed on this
cycle basis, not on a calendar month. Since cycles overlap months,
two cycles of meter data are needed to calculate a given calendar
month's meter use for these customers.
b. Recognizing these data limitations, certain provisions were
implemented as part of the Gas Accord so that CPGs could manage
their daily and monthly imbalances like the other marketers,
shippers and noncore customers. One of these provisions was the
Core Load Forecasting and Determination Service, which forecasts
the upcoming Gas Day usage for each CPG 24 hours and 48 hours prior
to the Gas Day, as well as provides a usage estimate on the morning
of the Gas Day. The CPG usage estimate provided on the Gas Day
itself is called the Determined Usage. The Determined Usage is used
by PG&E to determine two monthly imbalances for each CPG: the
Cumulative Imbalance and the Operating Imbalance.
(1) Cumulative Imbalances are the monthly accumulation of each
day's scheduled supply less Determined Usage. Cumulative
Imbalances are calculated at the end of each month and may be
traded, cashed-out or carried over to the subsequent month.
(2) Operating Imbalances are the difference between calendar month
Determined Usage and metered usage. Metered usage for a
calendar month is calculated by the appropriate weighting of
the measured cycle usage. An Operating Imbalance Statement for
a particular month is normally provided to customers two
months following the processing of the Cumulative Imbalance
Statement for the same month. This added time is necessary to
collect and process the billing cycle usage data needed to
calculate the indicated calendar month usage. These Operating
Imbalances may be traded into or out of storage, traded with
other customer Operating Imbalances for the same calendar
month, or under current provisions, carried over to the month
following the date on which the Operating Imbalance Statement
is issued.
c. To allow more flexibility in managing their total imbalances, CPGs
will now be able to trade Operating Imbalances with any Cumulative
Imbalances issued in the same month. The trading between Cumulative
and Operating Imbalances is subject to the following rules:
(1) Trades must occur in the regular monthly Cumulative Imbalance
trading period.
(2) Trades must move the total Operating Imbalance towards, but not
past, zero.
d. Accounting adjustments for CPGs as provided in Schedule G-BAL will
be included in their Operating Imbalance Carryover.
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OFO Settlement Agreement
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e. Currently, any Operating Imbalance remaining after the Trading
Period normally becomes the first gas through the meter in the
month following the trading period. Since an imbalance repayment
has no offsetting demand and can be relatively large, it is
important to spread these deliveries out over a longer period of
time so the impact on pipeline balancing and the possible need to
issue OFOs is minimized. This also allows positive and negative
Operating Imbalances to offset each other over time. Therefore, the
following process is adopted for CPGs to repay untraded Operating
Imbalances over approximately a one-year period: (1) An Operating
Imbalance Carryover account is established to accumulate (credit)
and repay
(debit) the untraded monthly Operating Imbalances.
(2) Each month, following the trading period, the untraded
Operating Imbalance is credited to the Operating Imbalance
Carryover.
(3) Each month, one-twelfth (1/12) of the Operating Imbalance
Carryover at the end of the prior month will be considered the
first transaction for that CPG and will be debited to its
Operating Imbalance Carryover.
(4) A CPG may also make a monthly election to clear its entire
Operating Imbalance Carryover if it is less than 5,000 Dth.
This will be considered the first transaction during the
calendar month following PG&E's receipt of written
notification, and will set the Operating Imbalance Carryover
to zero.
f. PG&E will continue to provide customers with information on the
basic assumptions and methods used to develop demand forecasts for
Core Procurement Groups. PG&E will also continue to assess and
implement appropriate and cost-effective modifications to its
forecasting processes, with the objective of reducing Operating
Imbalances.
6. Storage Allocation to Balancing
a. Settlement Parties agree that no additional storage assets will be
allocated to balancing at this time. Parties may agree in a future
settlement to either add or reduce the amount of PG&E storage
assets allocated to system balancing.
b. PG&E will provide the Settlement Parties, no later than the date
initial testimony is due in I.▇▇-▇▇-▇▇▇, with a report which
describes the cost of adding and/or allocating additional storage
assets to system balancing. This storage report will include the
cost of each component (inventory and compressors), the anticipated
effect on operations and OFOs, and the effect on rates.
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D. Provisions Designed to Reduce the Impact of OFOs
------------------------------------------------
1. OFO Notification
a. PG&E will continue to notify the market of system-wide and
customer-specific OFOs as soon as practically possible. Primary
notice will continue to be posted on INSIDEtracc. Notice will also
continue to be provided on PG&E's Pipe Ranger Web site. In addition
to electronic mail and/or a FAX for OFO notification, customers may
now also sign up to receive an alpha page, which replaces the less
effective "blast-paging."
b. PG&E currently provides the following information to the market for
system-wide OFOs:
(1) Date of the OFO.
(2) Tolerance Band in percent.
(3) Stage (i.e., 1, 2, 3, or 4) as established in this Agreement.
(4) Noncompliance Charge in $ per therm.
(5) Reason (i.e., High or Low pipeline inventory).
c. No tariff changes are needed to reflect these adjustments to PG&E's
OFO notification options or procedures.
2. Noncompliance Charges During an OFO
a. Experience with OFOs has indicated that some customers tend to
over-adjust their supply (and sometimes demand) in order to
minimize the risk of being outside the tolerance band and subject
to an OFO noncompliance charge. The objective in issuing an OFO is
to match the market reaction to the system need for imbalance
relief, and thereby permit the system to stay within operating
limits. A lower noncompliance charge which is closer to the
movement of commodity prices in the market should encourage parties
to more accurately adjust their supplies to their expected demand
under most OFO conditions.
b. PG&E still retains the option under the tariffs of commencing an
OFO at a higher stage and noncompliance charge, or even increasing
the stage later in the day.
c. The noncompliance charge for a Stage 1 OFO will be reduced from
$0.10 to $0.025 per therm. Another stage will be added after Stage
1 with a noncompliance charge of $0.10 per therm and a tolerance
range up to +/-20%. The table currently included in the Gas Rule
14, Section E, will be revised to the following:
Tolerance Band Noncompliance Charge
As a % of Usage Dollars Per Therm
Stage 1: up to +/-25% $0.025
Stage 2: up to +/-20% $0.10
Stage 3: up to +/-15% $0.50
Stage 4: up to +/-5% $2.50
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3. OFO Noncompliance Charge Exemption
a. Currently, some customers have difficulty in complying with
OFOs because the gas market generally requires gas commodity
purchases in packages of at least 5,000 Dth per transaction,
or charges a premium for "small or odd lot" deals.
b. All balancing entities will be exempt from OFO noncompliance
charges if their total monthly OFO noncompliance charges are
equal to or less than $1,000. This noncompliance charge
exemption will allow those customers with small imbalances to
avoid making supply or demand adjustments during an OFO, even
if their imbalance as a percent of their demand is outside the
allowable OFO tolerance band.
c. PG&E may prospectively withdraw this exemption or reduce the
exemption level if in PG&E's sole judgment this provision
contributes to an increase in OFOs. PG&E will provide notice
to, and will consult with, the Gas OFO Forum prior to making
such a change.
d. There shall be no exemptions from noncompliance charges during
EFOs or Involuntary Diversions.
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CPUC Promising Gas Options
I.▇▇-▇▇-▇▇▇
Comprehensive Gas OII
Settlement Agreement
January 28, 2000
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CPUC Promising Gas Options I.▇▇-▇▇-▇▇▇
Comprehensive Gas OII Settlement Agreement
Table of Contents
-----------------
1. INTRODUCTION........................................................................ 1
2. PROMISING OPTIONS WHICH ARE PUT IN PLACE BY THIS SETTLEMENT AGREEMENT............... 4
2.1 Cost and Rate Separation for Balancing Services [Self-Balancing Options].......... 4
2.2 Electronic Trading of Imbalances [Including Rights]............................... 8
2.3 Re-examine Utility Role in Core Procurement Once a Specified Competitor Market
Share Has Been Achieved.......................................................... 13
2.4 Eliminate Core Aggregation Transportation Thresholds After Adoption of Consumer
Protection Measures.............................................................. 14
2.5 Unbundle Utility Storage Costs for Core Customers [Served by CTAs]................ 14
2.6 Separate Costs and Rates for Core Utility [Procurement] Services. Treat Utility
Core Procurement Departments as Any Other Utility Customer....................... 18
2.7 Provide Details of Completed Transactions......................................... 19
2.8 Establish a Secondary Market [Trading System] via a Utility Electronic Bulletin
Board............................................................................ 19
2.9 Provide Real-Time, Customer-Specific Usage Data................................... 20
2.10 Provide Competitive Metering Technologies......................................... 22
2.11 Provide Competitive Billing Options to Customers Similar to Those Offered in the
Electric Industry................................................................ 25
3. PROMISING OPTIONS ALREADY IN PLACE FOR PG&E......................................... 27
3.1 Create Firm Tradable Intrastate Transmission Rights............................... 27
3.2 Establish a Secondary Market for Intrastate Transmission Capacity................. 27
3.3 Place the Utility At Risk for Unused [Transmission] Resources..................... 27
3.4 Create Firm, Tradable Storage Rights.............................................. 28
3.5 Establish a Secondary Market For Intrastate Storage Capacity...................... 28
3.6 Place the Utility At-Risk for Unused [Storage] Resources.......................... 28
3.7 Separate Utility Hub Services From Procurement Functions.......................... 29
3.8 Unbundle Utility Interstate Capacity Costs for Core Customers..................... 29
3.9 Eliminate Core Subscription Service............................................... 29
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Table of Contents (continued)
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4. PROMISING OPTIONS AND OTHER ISSUES WHICH ARE NOT TO BE LITIGATED PENDING FURTHER
SETTLEMENT DISCUSSIONS............................................................. 30
4.1 Develop Clear Procedures for Allocating [Firm] Capacity.......................... 30
4.2 Revise PG&E's Transmission Interconnection Policy, Terms and Conditions (Not an
Appendix C Item)................................................................ 30
4.3 Revise PG&E's Electric Generation Rate Design (Not an
Appendix C Item)................................................................ 30
4.4. Review PG&E's Local Transmission Reliability, Design Standards and Curtailment
Provisions (Not an Appendix C Item)............................................. 30
4.5 Investigate Mechanisms to Reduce the Costs of Transmission Service for Noncore
Customers Connecting To or Located Close To PG&E's Backbone Transmission
Facilities (Not an Appendix C Item)............................................ 31
5. PROMISING OPTIONS WHICH WERE SETTLED IN THE OFO SETTLEMENT AGREEMENT............... 31
5.1 Examine Strategies for Devoting More Assets to PG&E Balancing.................... 31
5.2 Implement Targeted Operational Flow Orders....................................... 31
5.3 Provide Pipeline Operator Demand Forecasts Broken Down by
Customer Class.................................................................. 32
6. NO ISSUES REMAIN TO BE LITIGATED IN I.▇▇-▇▇-▇▇▇.................................... 32
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CPUC Promising Gas Options I.▇▇-▇▇-▇▇▇
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1. INTRODUCTION
1.1 Purpose: The purpose of this Comprehensive Gas OII Settlement
Agreement ("Settlement Agreement") is to address the most promising
options and other issues presented in Investigation (I.)▇▇-▇▇-▇▇▇.
Specifically, the goal of this Settlement Agreement is to resolve all
PG&E issues that would otherwise be litigated in I.▇▇-▇▇-▇▇▇.
1.2 Parties: This Settlement Agreement is entered into by the Settlement
Parties ("Parties"), as identified by their attached signatures.
Parties agree to actively support this Settlement Agreement in
I.▇▇-▇▇-▇▇▇ and to not oppose any provision of this Settlement
Agreement in any regulatory, legislative or judicial forum. Parties
agree that this Settlement Agreement is consistent with the provisions
of AB 1421.
1.3 Background: In Decision (D.)▇▇-▇▇-▇▇▇, the California Public Utilities
Commission ("CPUC" or "Commission") identified a number of promising
options for continued restructuring of the California natural gas
industry. These options were summarized in Appendix C of that
decision. This Settlement Agreement uses the Appendix C notation for
reference.
1.4 Commission Directive: In her ruling of November 5, 1999,
Administrative Law Judge ▇▇▇▇▇▇ ▇. ▇▇▇▇▇ directed parties to file a
settlement of all or some of the issues in this docket by January 28,
2000. In the absence of a complete settlement, Parties were directed
to file prepared testimony on all non-settled issues by March 7, 2000.
1.5 Summary of Agreement and Conditions: This Settlement Agreement settles
all of the issues raised by the most promising options being
investigated in I.▇▇-▇▇-▇▇▇. No issues require further litigation in
this proceeding for PG&E. This Settlement Agreement distinguishes
between promising options being put in place, those already in place
on the PG&E system, those being negotiated elsewhere, and those
addressed in the OFO Settlement filed with the Commission on October
22, 1999.
The Gas Accord, as approved by the Commission in D.▇▇-▇▇-▇▇▇, will
continue through December 31, 2002, and is only modified as
specifically agreed to in this Settlement Agreement, subject to future
decisions by the CPUC. PG&E agrees to initiate post-Gas Accord
settlement discussions promptly following the Commission's approval of
this Settlement Agreement.
This Settlement Agreement is a negotiated compromise and is broadly
supported by parties who are marketers, gas suppliers, shippers,
wholesale and retail end-use customers, storage operators and
regulatory representatives, as well as the Coalition of California
Utility Employees. Nothing contained herein shall be deemed to
constitute an admission or an acceptance by any party of any fact,
principle, or position contained herein, except to the extent that
Parties, by signing this Settlement Agreement, acknowledge that they
pledge support for Commission approval and subsequent implementation
of all these provisions.
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This Settlement Agreement is to be treated as a complete package and
not as a collection of separate agreements on discrete issues or
proceedings. To accommodate the interests of different parties on
diverse issues, the Parties acknowledge that changes, concessions, or
compromises by a party or parties in one section of this Settlement
Agreement necessitated changes, concessions, or compromises by other
parties in other sections.
All Parties' obligations under this Settlement Agreement are
conditioned upon the CPUC issuing a decision approving this Settlement
Agreement without modification. If the CPUC modifies the Settlement
Agreement, each party reserves the right to withdraw its support for
the Settlement Agreement.
1.6 Cost Recovery: PG&E will recover $700,000 in costs from
customers/ratepayers to implement and maintain the following
provisions of this Settlement Agreement. If costs exceed this amount,
they will be borne by PG&E.
Section 2.1 Cost and Rate Separation for Balancing Services
[Self-Balancing]
Section 2.2.2 Anonymous Monthly Imbalance Trading
Section 2.2.3 Trading OFO Day Imbalance Rights
Section 2.8 Secondary Market Electronic Trading System
Upon approval of this Settlement Agreement, PG&E will debit the
specified amount of $700,000 to the Balancing Charge Account (BCA).
This debited amount will not be subject to a reasonableness review by
the Commission. Also as provided in Sections 2.2.2.3.6, 2.2.3.5 and
2.8.4 below, PG&E will credit the BCA with a portion of the
transaction fees received from certain trading activities.
1.7 Implementation and Term: Within 60 days of a Commission decision
approving this Settlement Agreement without modification, PG&E shall
file an advice letter in compliance with that decision. In order to
facilitate the implementation of the Settlement Agreement and to
enable parties to promptly respond to the compliance advice letter,
PG&E agrees to serve the parties in I.▇▇-▇▇-▇▇▇ with pro forma tariff
sheets reflecting the provisions of the Settlement Agreement within 60
days of the filing of this Settlement Agreement. Unless stated
otherwise, those provisions of this Settlement Agreement which do not
require tariff changes shall become effective upon approval by the
Commission. Those provisions requiring tariff changes shall become
effective at such time as indicated in a Commission decision,
resolution, or letter of approval. This Settlement Agreement shall
continue in effect through December 31, 2002, or until such other
dates as specified in this Settlement Agreement.
1.8 Implementation Date For Changes Put In Place By This Settlement
Agreement Which Affect Core Transportation Agents (CTAs):
1.8.1 PG&E is not be able to provide PG&E-consolidated gas billing for
gas-only customers until its billing system replacement project
is completed ("Billing Availability Date"). PG&E commits to
providing PG&E-consolidated billing for such customers upon
completion of its billing system replacement project. Absent
unforeseen circumstances, PG&E intends to provide this
functionality by no later than the end of 2002 based on PG&E's
current project plan. In the event of any unexpected delays, PG&E
will notify the Parties of the possible delays as soon as
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is reasonably practical. Parties agree that under AB 1421 and
other relevant law, nothing in this Settlement Agreement will
require PG&E to offer PG&E-consolidated gas billing for gas-only
customers prior to the Billing Availability Date.
1.8.2 The following sections of this Settlement Agreement will be
implemented independent of the Billing Availability Date:
2.1 Cost and Rate Separation for Balancing Services
[Self-Balancing Option]
2.2.2 Anonymous Monthly Imbalance Trading
2.2.3 Trading OFO Day Imbalance Rights
2.5 Unbundle Utility Storage Costs for Core Customers
[Served by CTAs]
2.7 Provide Details of Completed Transactions
2.8 Establish a Secondary Market Electronic Trading
System
2.9 Provide Real-Time Customer-Specific Usage Data
2.10 Provide Competitive Metering Technologies
2.11.4 Terminate Information ▇▇▇▇ Requirement
2.11.5 Provide Billing Credits For CTA Consolidated Billing
1.8.4 This Settlement Agreement is contingent on a final decision by
the CPUC that contains an express finding that under AB 1421 and
any other relevant law, nothing in this Settlement Agreement
requires PG&E to offer consolidated gas billing for gas-only
customers prior to the Billing Availability Date.
1.8.5 If, after approval of this Settlement Agreement, the CPUC or a
court issues a decision finding that certain changes resulting
from this Settlement Agreement require PG&E to offer consolidated
gas billing for gas-only customers prior to the Billing
Availability Date, then such changes shall not be made available
until the Billing Availability Date, notwithstanding Section
1.8.2 of this Settlement Agreement.
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2. PROMISING OPTIONS WHICH ARE PUT IN PLACE BY THIS SETTLEMENT AGREEMENT
2.1 Cost and Rate Separation for Balancing Services [Self-Balancing
Options]
2.1.1 Summary of D.▇▇-▇▇-▇▇▇: The creation of separate, avoidable
rates for balancing services might facilitate the entry of
competitors who would provide balancing services along with
procurement, storage, as well as intrastate and interstate
transmission. Cost and rate separation for balancing services
might also facilitate the provision of a variety of balancing
services on the part of the utility as well as competitors.
Examples of such services would include daily balancing with
varying tolerance bands and penalties as well as more generous
monthly balancing tariffs, with costlier charges. The provision
of a daily balancing option may be necessary in order to
implement other reforms such as electronic trading of
imbalances as well as cost and rate separation for balancing
services. The costs and benefits of the daily balancing option
should be considered in the next phase of this inquiry. (pp.
38-40, Findings of Fact (FoF) 22, Conclusions of Law (CoL) 8,
Appendix C)
2.1.2 Gas Accord Balancing Provisions:
2.1.2.1 Currently, PG&E's pipeline (California Gas Transmission
or CGT) provides a limited amount of balancing for
customers to manage their differences between supplies
and usage caused by a variety of factors, including
end-user demand uncertainty, unplanned equipment
outages, and price arbitrage. PG&E's pipeline must also
manage other imbalances including shrinkage, pipeline-
to-pipeline imbalances, California gas production
imbalances and imbalances due to forecast error for
core loads on the day of gas flow.
2.1.2.2 The resources used by the pipeline for balancing
include the gas in the pipelines (called pipeline
inventory or linepack) and the firm storage assets
assigned to balancing under the Gas Accord. If the
pipeline inventory is forecast to exceed operating
limits, Operational Flow Orders (OFOs) are issued,
which impose daily balancing limits and penalties for
that day. If conditions warrant, Emergency Flow Orders
(EFOs), involuntary diversions or trimming receipt
point deliveries can also be implemented to protect the
integrity of the pipeline.
2.1.2.3 Balancing entities are limited to a monthly imbalance
of +/-5 percent. After the end of the month, they can
trade imbalances outside this range. Following trading,
amounts outside +/-5 percent are cashed-out. There are
no specific daily balancing limits, except on OFO or
EFO days, although customers have daily nomination
limits.
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2.1.3 Self-Balancing Option Provisions: As part of this Settlement
Agreement, PG&E will develop and implement an unbundled daily
balancing option, which is called the Self-Balancing option. This
option allows customers to receive a credit for a portion of the
balancing costs currently bundled in the backbone rate, and is
designed to reduce the need for PG&E to make systems changes for
accounting, operations and tracking of daily imbalances for a
significant number of customers. The following provisions will
apply to Self-Balancing.
2.1.3.1 Bundled Balancing: Bundled monthly balancing provided by
-----------------
PG&E remains the default balancing service for any customer
who does not elect the Self-Balancing option. The intent of
the Parties is that the offering by PG&E and the election
by customers of the Self-Balancing option will not
adversely affect the availability, reliability or cost of
bundled balancing, nor will it cause an increase in the
frequency of OFOs or EFOs. As provided in Section 2.1.3.8
below, the OFO Forum will monitor these effects, and meet
to discuss and resolve concerns if such adverse effects
occur.
2.1.3.2 Availability and Election of Self-Balancing Option: The
--------------------------------------------------
Self-Balancing option is available to noncore customers,
wholesale customers, and core procurement groups (CPGs).
For CPGs, a daily forecast of demand will continue to be
used to measure daily imbalances, similar to how OFOs are
done. PG&E's Core Procurement Department agrees that for
the term of this Settlement Agreement it will not elect the
Self-Balancing option. Noncore Balancing Aggregation
Agreements (NBAAs) may contain either Self-Balancing
customers or monthly balancing customers, but not combine
Self-Balancing and monthly balancing customers (since the
balancing rules which apply to each are quite different).
2.1.3.3 Transmission Rates: All of the costs agreed to be included
------------------
in rates for system balancing in the Gas Accord will
continue to be included in backbone transmission rates.
2.1.3.4 Allocation of Balancing Storage Assets: For purposes of
--------------------------------------
this Settlement Agreement, through March 31, 2003, eighty
percent (80%) of the balancing storage assets are unbundled
and made available to the self-balancing option. However,
all these storage assets remain with the pipeline unless a
customer elects the Self-Balancing option. For these
customers, their share of the balancing storage assets will
be assigned to and remarketed through PG&E's at-risk
unbundled storage program. If a customer elects to return
to monthly balancing from Self-Balancing during the annual
election period, then the same amount of storage is
reassigned back to pipeline balancing. The amount is
calculated as a pro rata share of the unbundled balancing
storage assets based on the customer's annual average usage
as a percentage of PG&E's average annual system usage.
2.1.3.5 Limitations on Self-Balancing Option: The elections for
------------------------------------
Self-Balancing are limited to 50 percent of the total
storage balancing assets of 2.2 Bcf of inventory, 50 MMcf
per day of injection and 70 MMcf per day of
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withdrawal. Once this limit is neared or reached, the OFO
Forum will meet to consider lifting this cap and whether
other adjustments are needed to PG&E's operating parameters
to ensure both the integrity of pipeline operations and the
benefits to the market of the Self-Balancing option.
2.1.3.6 Credit for Self-Balancing: Those customers and CPGs
-------------------------
electing Self-Balancing will receive a credit equal to
$0.0050 per decatherm times their actual monthly metered
usage.
2.1.3.7 Analysis of Storage Balancing Assets: The Parties agree
------------------------------------
that a first priority for the OFO Forum is to evaluate the
level of storage assets made available for pipeline
balancing. By February 1, 2001, the OFO Forum will
recommend to the Commission whether the amount of storage
capacity allocated to balancing service should be revised.
If the recommendation is for an increase, the OFO Forum
will also recommend the source of this additional firm
storage capacity. Possible sources include PG&E's at-risk
unbundled storage program, capacity rejected by CTAs
pursuant to the provisions of Section 2.5, non-PG&E on-
system storage, or some combination thereof. Additionally,
the OFO Forum will recommend rate treatment for the costs
associated with a recommended change in allocated balancing
storage capacity. Parties agree that there will be no
decrease in assets dedicated to system balancing (except as
provided herein for self-balancing elections), nor rate
decreases, during the term of this Settlement Agreement
Provision.
2.1.3.8 Monitoring the Effect of Self-Balancing on OFOs: The
-----------------------------------------------
Parties, through the OFO Forum, will monitor the response
to the Self-Balancing option and the impact on OFOs. After
reviewing the data, the OFO Forum may recommend revising
the Self-Balancing option and/or pipeline operating
parameters.
2.1.4 Self-Balancing Option Terms and Conditions: Customers electing
the Self-Balancing option will be subject to the following terms
and conditions.
2.1.4.1 Election of the Self-Balancing option is made annually in
February and is effective for a minimum term of one year
from April 1 through March 31. After the initial year, a
customer who previously elected to Self-Balance, may elect
back to monthly balancing during the election period. A
multi-year election to Self-Balance may also be made, but
not extending beyond March 31, 2003. Circumstances may also
arise which would require a customer to change its self-
balancing election during the year.
2.1.4.2 Customers will be responsible for tracking their own daily
imbalance position. PG&E will not be required to provide
warnings or other notice, even if a customer is falling
outside the prescribed Self-Balancing requirements.
2.1.4.3 Noncore customers must have meters which record daily
usage, even if these meters are only read once per month.
The cost of adding daily usage recording devices and/or
data access is the responsibility of the customer.
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Small meters (meter capacity less than 100 dth per day) at
a customer facility with large hourly recording meters are
exempted from the hourly recording requirement and will be
included in daily calculations using a forecast of daily
usage based on averages derived from monthly data.
2.1.4.4 Daily usage for CPGs electing the Self-Balancing option
will be based on a forecast of their customers' gas usage.
For CPGs whose demand is smaller than three percent (3%) of
the core market (based on annual demand), daily usage will
be determined using the first 24-hour forecast available
each day. For CPGs whose demand is greater than or equal to
three percent (3%) of the core market, daily usage will be
determined using an end of the gas day forecast. For any
CPG electing Self-Balancing, the applicable daily usage
forecast will also be used to calculate its monthly
cumulative imbalance available for trading or carry forward
as described below in Section 2.1.4.9. If the annual demand
of CPGs electing Self-Balancing exceeds ten percent (10%)
of the total core market annual demand, then the largest
CPG(s) electing to self-balance will have their daily usage
determined based on the end of the gas day forecast, such
that the sum of the demands for the remaining self-
balancing CPGs continuing to use the 24-hour forecast does
not exceed the ten percent (10%) limit. The OFO Forum may
review and make recommendations to address impacts on OFOs
and/or EFOs that may arise due to CPGs electing Self-
Balancing.
2.1.4.5 Customers electing the Self-Balancing option will be
subject to two imbalance limits each day.
2.1.4.5.1 The daily imbalance cannot exceed plus or minus ten
percent (+/-10%) of that day's metered or forecast
usage, except on OFO or EFO days; and
2.1.4.5.2 The accumulated daily imbalance cannot exceed plus or
minus one percent (+/-1%) of that month's usage. Each
month's usage for this purpose will be set prior to
the month based on historical usage and forecast
patterns.
2.1.4.6 Each balancing entity subject to the Self-Balancing limits
specified above is still subject to system-wide and
customer-specific OFOs. On those days, the OFO or EFO
tolerance band requirements and associated noncompliance
charges will be imposed, and the +/-10 percent
Self-Balancing requirement will not apply for that OFO or
EFO day. However, the accumulated daily imbalance
requirement will still apply.
2.1.4.7 PG&E will calculate the daily imbalances after the calendar
month for each noncore customer or balancing entity
electing this option after processing the applicable meter
data. Daily imbalances for CPGs will be based on their
daily usage as described in Section 2.1.4.4 above.
2.1.4.8 Noncompliance charges will be calculated for customers
electing the Self-Balancing option as the sum of the
following, except as provided in Section 2.1.4.8.4, and
will be recorded in the Balancing Charge Account (BCA).
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Rule 601 et seq. of the FERC Rules of Practice. Rule 408 of the Federal
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2.1.4.8.1 For each non-OFO or non-EFO day, a noncompliance
charge equal to $1.00 per decatherm per day for each
day when the daily imbalance exceeds +/-10 percent of
the daily metered or determined usage.
2.1.4.8.2 For each OFO or EFO day, a noncompliance charge is
calculated using the applicable OFO or EFO tolerance
level and noncompliance charge.
2.1.4.8.3 For each day including OFO and EFO days, a
noncompliance charge equal to $1.00 per decatherm per
day for each day when the accumulated daily imbalance
exceeds +/-1 percent of the preset monthly usage.
2.1.4.8.4 For each OFO day or EFO day on which a noncore
customer or balancing entity electing the
Self-Balancing option is exceeding its accumulated
imbalance limit in a direction opposite to that of the
OFO or EFO situation, there will be no noncompliance
charge under Section 2.1.4.8.3 above. For example,
under a high inventory OFO, a balancing entity with a
negative accumulated imbalance exceeding -1% of its
preset monthly usage would not receive a noncompliance
charge for this situation. However, if the accumulated
imbalance is not corrected to within the +/-1 percent
limit on the next non-OFO or non-EFO day,
noncompliance charges will apply.
2.1.4.9 Monthly cumulative imbalance trading is allowed. Any gas
imbalances remaining after the trading period that are in
excess of plus or minus one percent (+/-1%) of the monthly
usage will be cashed out at the highest cash-out price
indicated in Schedule G-BAL for imbalances in excess of
10%. Any carry forward amount will set the beginning
accumulation level for the next month. No daily trading
during the month of imbalance position or rights is
allowed. However, trading of OFO day imbalance rights
(chips) will be allowed as provided in Section 2.2.3 below.
2.1.4.10 Following each annual election period, PG&E will report
within 30 days on its Pipe Ranger Web site the percentage
(based on annual demands) of the core and noncore markets
electing to Self-Balance. Specific customers or entities
electing the Self-Balancing option will not be identified.
2.2 Electronic Trading of Imbalances [Including Rights]
2.2.1 Summary of D.▇▇-▇▇-▇▇▇: The Commission provisionally finds that
shippers should be allowed to trade or sell imbalance rights
since they pay for a balancing tolerance as a component of their
intrastate transmission rates and are entitled to have the plus
or minus tolerance on a daily or monthly basis. The trading of
imbalance rights would give shippers the ability to adapt to
daily balancing rules, where they apply, during a given day's
nomination cycles. The Commission finds the concept of imbalance
trading to hold sufficient promise to merit further inquiry. The
Commission also encourages parties to consider whether a
mechanism could be developed to produce the hoped-for benefits
versus its costs. (pp. 41-44, FoF 24-26, Appendix C)
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Rule 601 et seq. of the FERC Rules of Practice. Rule 408 of the Federal
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2.2.2 Anonymous Monthly Imbalance Trading
2.2.2.1 Current PG&E Platform for Monthly Imbalance Trading: PG&E
currently provides a platform on its Pipe Ranger Web site
for entities to confirm trades of same month cumulative and
operating imbalances. This Internet-based platform allows
balancing entities who have negotiated imbalance trades
with another balancing entity to inform PG&E of the
imbalance trade using the Internet. Basically, one
balancing entity electronically enters the results of the
negotiated trade, and the other balancing entity confirms
the trade. This platform validates whether the confirmed
trade is in compliance with the current imbalance trading
rules set forth in PG&E's tariff Schedule G-BAL. If not,
the trade is rejected. this platform currently does not
provide for posting offers to buy or sell monthly
imbalances, or for facilitating trading such imbalances.
Entities contact each other directly to work out the trade
details, including price.
2.2.2.2 Provider of Electronic Imbalance Trading System: PG&E will
contract with a Third Party Service Provider (TPSP) to
provide anonymous electronic trading of cumulative and
operating imbalances, i.e., the trading of actual imbalance
gas, not rights. PG&E intends to enter into a sole-source
contract with an affiliate of Altra Energy Technologies,
Inc. (ALTRA(R)) to provide the monthly imbalance trading
platform using their Altrade(R)product. The sole source
provision of this contract will be in effect through
December 31, 2002. Once PG&E finalizes its contract with
ALTRA, a copy of the contract will be provided to the
Parties, subject to a confidentiality agreement. At the end
of this sole-source period, any other TPSP may provide
service in competition with ALTRA. At that time, PG&E will
provide a customer service and data interface with all
interested TPSPs offering electronic imbalance trading.
2.2.2.3 Principles for Imbalance Trading System: The following
principles are agreed to in order to mitigate concerns
about the market relying on a sole-source provider during
this market development period.
2.2.2.3.1 PG&E will continue to provide its platform for
entities to post and confirm monthly imbalance trades
without charging transaction fees.
2.2.2.3.2 Use of the anonymous trading platform is voluntary.
2.2.2.3.3 ALTRA is a logical sole-source provider. ALTRA has
contracts with about 80% of the entities for gas
commodity trading, and is well recognized as an
industry leader in building and servicing electronic
trading platforms.
2.2.2.3.4 Entities with currently-effective ALTRA contracts will
not have to pay added monthly subscription fees. A
smaller fixed subscription fee will be made available
for those entities who only want to use ALTRA for
imbalance trading, and not commodity trading. The
monthly subscription fee will be credited against
transaction fees up to that amount. Subscription fees
are needed in addition to transaction fees because
experience is that entities will use the price
discovery
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Rule 601 et seq. of the FERC Rules of Practice. Rule 408 of the Federal
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information available on the trading screens to do their
own deals outside the trading platform. These deals can
then be reported through PG&E's existing platform, thus
avoiding transaction fees.
2.2.2.3.5 Each trade will be subject to buyer and to seller
transaction fees for each decatherm traded. The transaction
fee provides an incentive for ALTRA to encourage trading
volume which in turn improves liquidity and price
discovery. These fees will be charged in a non-
discriminatory manner, but could include tiered pricing.
The transaction fees will be capped during the sole-source
period.
2.2.2.3.6 PG&E will retain a share of ALTRA's transaction fee which
offsets PG&E's transaction and credit costs, as well as
reflects the value PG&E brings to this service. The fee
sharing will also provide an incentive to PG&E to encourage
use of this trading service. The fee shall be established
by ALTRA with any revenues shared between ALTRA and PG&E
equally. One-half of the PG&E portion of these transaction
fees will be recorded as a credit to the BCA to help offset
the costs incurred to implement this trading system. PG&E
will include the specific fee provisions in its tariffs
pursuant to Section 1.7 above.
2.2.2.3.7 ALTRA will operate the trading system and retain ownership
of all software. ALTRA will be responsible for all
maintenance and operation costs associated with operating
the Altrade trading platform.
2.2.2.3.8 PG&E shall not influence, in any way, ALTRA's selection of
trading partners, business associations or contracts with
any third party operating on the PG&E system, other than in
matters of routine credit and nomination capacities
envisioned by this Settlement Agreement.
2.2.2.4 System Features for Electronic Imbalance Trading System: The
following provisions will be part of the monthly imbalance
trading system limitations and features.
2.2.2.4.1 The electronic trading platform will allow a balancing
agent to post either a bid to purchase imbalance gas or to
post an asking price to sell imbalance gas. Other parties
will be able to monitor these postings and accept the
posted offer or make a counter-offer. When two parties
agree on price, ALTRA will manage the transaction by adding
imbalance gas to the Purchaser's account and subtracting
imbalance gas from the Seller's account. The Purchaser is
then billed for the agreed upon price, and payment is made
to the Seller for the same amount.
2.2.2.4.2 Anonymous trading on ALTRA platform will not be required to
abide by all the imbalance trading limitations in Schedule
G-BAL during the trading period. However, the final
summation of the imbalance trades completed on ALTRA's
trading platform and those posted on PG&E's platform will
be subject to the Schedule G-BAL limitations and cash-out
provisions. The limitations include: no trading across
months;
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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
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trading cumulative imbalances towards zero; trading results
in a cumulative imbalance that is within the range of plus
or minus three percent of usage past zero; and trading into
or out of on-system storage accounts which have documented
inventory gas or space available.
2.2.2.4.3 PG&E and ALTRA will establish an electronic link to
transfer data on current account balances and to update
these accounts once the imbalance trading period ends.
ALTRA will send its trading results to PG&E. PG&E will add
additional trades that are confirmed through PG&E's current
platform and add trades between storage accounts. The final
ending imbalance position for each balancing entity will be
used to determine any cashout or carry forward amounts
based on the rules in Schedule G-BAL.
2.2.2.4.4 Entities will be subject to trading limitations based on
individual credit limits and system operating limitations.
PG&E will revise its credit-worthiness requirements in its
tariffs to reflect these transactions. PG&E will be
responsible for providing ALTRA with these trading limits.
ALTRA will not allow an entity to complete a trade if their
limit would be exceeded by completing the trade.
2.2.2.4.5 PG&E will accept the credit risk for entities which are
PG&E customers approved for this program, including
designated marketers, NBaas, and CTas. If a Purchaser
accepts a trade and fails to pay its trading position
(either buying or selling imbalance gas) when billed by
ALTRA, PG&E will guarantee payment to the Seller in the
transaction. PG&E will then take collection action against
the Purchaser, including late fees and, if appropriate,
cashouts in accordance with the G-BAL requirements.
2.2.2.4.6 To encourage additional liquidity, ALTRA may allow market
makers that have no imbalances on the PG&E system to
participate in imbalance trading. ALTRA will be responsible
for credit approval and collection for these market makers,
pursuant to its agreement with PG&E. Market makers will be
required to have zero imbalances at the end of the trading
period. ALTRA may institute additional rules to enforce
this requirement and other conditions needed to conduct
business.
2.2.2.4.7 On-system, non-PG&E storage facilities may participate
under the same terms and conditions applicable to imbalance
trading with PG&E's storage and/or market center.
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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
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2.2.3 Trading OFO Day Imbalance Rights
2.2.3.1 Objectives: PG&E and ALTRA will implement a mechanism to allow
trading of imbalance rights for each OFO day using the same
electronic platform as for monthly imbalance trading. The
objective is to provide balancing entities the opportunity
after the fact to reduce or eliminate OFO noncompliance
charges, and to create value for those entities who are within
the specified OFO day tolerance band. Trading these rights
does not change the physical imbalance position of the entity
or the pipeline. Trading these OFO day rights also avoids the
problem of significant retroactive accounting adjustments
which would be needed if physical imbalances for the OFO day
were traded.
2.2.3.2 Market Benefits: A daily balancing tolerance level is
specified for each day an OFO is called. This tolerance level
generally ranges from +/-2% to +/-16%. If a balancing entity
has an imbalance outside this tolerance level for that OFO
day, it is subject to noncompliance charges. If a balancing
entity has an imbalance that is within this tolerance level
for that OFO day, that entity receives no benefit for helping
the situation. With imbalance rights trading, there is an
opportunity for the balancing entity that is below the
tolerance level to gain value from this position, while
helping the balancing entity outside the tolerance band to
reduce their noncompliance charges.
2.2.3.3 Establishing and Trading Imbalance Rights: The approach is to
establish imbalance rights, or chips, for each balancing
entity for each OFO day, and then to allow the trading of
these rights. The following describes this mechanism.
2.2.3.3.1 The imbalance rights or chips are calculated as the
difference between the entities' imbalance and the
tolerance level on that OFO day. Chips are positive
(black) for those entities whose imbalances are within
the tolerance level, and negative (red) for those
entities that are outside the tolerance level and subject
to noncompliance charges. One chip is given for each
decatherm of difference.
2.2.3.3.2 Each chip is dated corresponding to a specific OFO day.
Chips can only be traded with those of the same date. In
other words, imbalances and noncompliance charges cannot
be traded between OFO days. Unlike cumulative imbalance
trading, gas in storage accounts will not be eligible to
create positive chips or to offset a negative chip
position during the imbalance rights trading period.
Trading between different OFO days and using storage
after the gas day occurs would change the incentive of
balancing agents to comply with the OFO on that
particular day. Trading of chips does not change these
incentives to comply with the OFO order.
2.2.3.3.3 Chips are cleared after the month is over. For example,
if there were five different OFO days during the previous
month, each balancing entity would have five separate
trading accounts and associated chips.
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2.2.3.3.4 For each individual OFO day, entities with positive
(black) chips will be able to sell them at a mutually
agreed upon price to those entities needing to offset
their negative (red) chips. The market would establish
the price for positive chips. It is likely that the price
to buy positive chips would be much lower than the
noncompliance charge if a large number of entities are
below the tolerance band and are competing to sell their
positive chips. When only a few entities have positive
chips for sale, the price would likely be close to the
noncompliance charge, but should never exceed the
noncompliance charge.
2.2.3.3.5 Those entities with net negative (red) chips remaining
after the trading period would be billed for the
commensurate noncompliance charges for the related OFO.
It is possible, although not likely, that an entity who
was physically in balance during the OFO could end up in
a negative chip position and pay noncompliance charges.
2.2.3.4 Electronic Trading and Confirmation System: Electronic trading
and electronic confirmation of offline trades of OFO day
imbalance rights (chip) will be included as part of the sole-
source contract with ALTRA, and subject to the terms of that
contract. Under this contract, ALTRA and PG&E will establish
the necessary interfaces, and ALTRA will provide the necessary
screens and trading platform. PG&E will modify its GTS and
accounting systems to verify compliance with the trading
rules, to record the trades, and to adjust the payments of
noncompliance charges accordingly.
2.2.3.5 Electronic Trading Fees: A monthly subscription fee will be
required if the customer does not already subscribe to ALTRA.
A smaller fixed subscription fee will be made available for
those entities who only want to use ALTRA for imbalance rights
trading, and not commodity trading. ALTRA will charge a
transaction fee to both the buyer and seller performing
electronic trading or electronic confirmation of offline
trades. This fee will be capped, and any discounts made
available on a nondiscriminatory basis. PG&E will receive
fifty percent (50%) of these fees, which will be recorded as a
credit to the BCA to help offset the costs for implementing
this trading system. PG&E will include the specific fee
provisions in its tariffs pursuant to Section 1.7 above.
2.3 Re-examine Utility Role in Core Procurement Once a Specified Competitor
Market Share Has Been Achieved
2.3.1 Summary of D.▇▇-▇▇-▇▇▇: The Commission recommends the re-examination
of local distribution company core procurement and the default
provider function if the market share exceeds 30% of the number of
customers, but even at that point the Commission has seen no
compelling reason to eliminate local distribution company
procurement as an option for customers. (pp. 50-59, Appendix C)
2.3.2 Resolution: Parties agree that there is no need to litigate nor for
the Commission to further examine the utility role in core
procurement in this proceeding.
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Rule et seq of the FERC Rules of Practice, Rule 408 of the Federal
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2.4 Eliminate Core Aggregation Transportation Thresholds After Adoption of
Consumer Protection Measures
2.4.1 Summary of D.▇▇-▇▇-▇▇▇: The Commission believes the lifting of the
core aggregation threshold and core participation cap will expand
the competitive options available to residential and small
commercial customers. In Ordering Paragraph 11, the Commission
recommends to the California Legislature that the consumer
protection measures proposed by the Commission's Energy Division be
immediately adopted by statute. The Commission also recommends that
the Legislature provide an exception to Senate ▇▇▇▇ 1602 to allow
the Commission to remove the current restrictions that limit
participation in the utilities' Core Aggregation Transportation
programs. The exception would allow the limits to be removed before
January 1, 2000, but after the Commission has implemented the
appropriate consumer protection measures. (pp. 59-61, FoF 30,
Ordering Paragraph (OP) #11, Appendix C)
2.4.2 Market Threshold: Under the Gas Accord, PG&E eliminated the market
limit threshold of 10 percent, and no further action is needed.
2.4.3 CTA Participation Threshold: Under the Gas Accord, PG&E reduced the
minimum size for core aggregation (CTA) participation from 250,000
to 120,000 therms per year. Parties agree that no change to this
threshold is necessary in this proceeding or during the term of
this Settlement Agreement.
2.5 Unbundle Utility Storage Costs for Core Customers [Served by CTAs]
2.5.1 Summary of D.▇▇-▇▇-▇▇▇: The Commission recommends exploration of
the unbundling of storage costs for core customers. (p.49)
2.5.2 Current CTA Storage Requirements: Under the Gas Accord, each Core
Transportation Agent (CTA) is assigned a pro rata share of the
total core allocated storage. This assignment is based on the total
historical winter usage of their customers. PG&E's tariff Schedule
G-CT requires that CTAs must fill and maintain their allocated
storage inventory within specified limits to aid in customer cold
weather system reliability.
2.5.3 Unbundling Storage Costs for CTAs: Parties agree to unbundle core
storage costs for CTAs during the remainder of the Gas Accord
period pursuant to the provisions below. Any further unbundling of
storage costs for all core customers will be considered only in the
context of the post-Gas Accord structure.
2.5.4 Basic Provisions: The following describes the structure and timing
of the CTA storage choice. Final details will be included in the
tariff changes needed to implement this program.
2.5.4.1 Core Storage Rate Treatment: As of the effective date of the
---------------------------
tariffs implementing this provision of the Settlement
Agreement, core storage costs will be recovered from PG&E's
Core Procurement Department customers through monthly core
procurement rates and from CTAs through monthly fees to the
extent they accept an allocation of core storage on
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Rule 601 et seq. of the FERC Rules of Practice, Rule 408 of the Federal
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behalf of their core transport customers, subject to
balancing account treatment up to the limits described below.
Cost shifts among core customers are to be minimized and no
costs are shifted to noncore customers.
2.5.4.2 CTA Storage Allocations: An allocation of storage inventory,
-----------------------
injection and withdrawal capacity to CTAs will continue to be
calculated in the same manner as is currently provided for in
Schedule G-CT. This allocation is based upon the historical
total winter throughput of CTA customers and the BCAP-adopted
winter throughput of all core customers. A core storage
allocation will continue to be calculated each February,
based upon the CTA group contracted volumes for the
subsequent winter season using the Direct Access Service
Requests (DaSRs) that have been processed to date.
2.5.4.3 CTA Option to Accept or Reject Storage Allocations: Each year
--------------------------------------------------
between about February 15 and March 1, CTAs will be given the
option to accept or reject their Annual Allocation of core
storage, for the storage year of April 1 through March 31, in
ten percent (10%) increments. CTAs will be able to make
adjustments to their annual election for increases or
decreases in loads during the Intra-Year Adjustment period
described below.
2.5.4.4 Initial Partial Year Option: If tariffs to implement this
---------------------------
provision are approved such that implementation can begin on
or before December 1, 2000, any CTA may reject all or a
portion of its current core storage allocation in ten percent
(10%) increments for the April 1, 2000 through March 31, 2001
storage season, subject to the Cap specified in Section
2.5.4.5 below. A CTA rejecting storage must sell the gas from
the portion of its storage account that it rejects to PG&E's
Core Procurement Department at a weighted average Core
Procurement price (Schedule G-CP) for the months that the
Core Procurement Department has injected gas during its
current or most recent injection season. A CTA must also
certify Alternate Resources pursuant to Section 2.5.4.11
below. The PG&E Core Procurement Department's Benchmark under
its Core Procurement Incentive Mechanism (CPIM) will be
adjusted by adding the costs associated with the purchase of
this CTA storage gas.
2.5.4.5 Cap on Rejected Storage Allocations: During the term of this
-----------------------------------
Settlement Agreement, the total amount of core storage
allocations that can be rejected by all of the CTAs is capped
each storage season as follows for inventory, with
proportionate injection and withdrawal rights.
Storage Season Cap On Rejected Share of Total
April 1 - March 31) CTa Storage Core Storage
------------------- ----------- ------------
2000-2001 1.64 Bcf 5%
2001-2002 3.28 Bcf 10%
2002-2003 4.92 Bcf 15%
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To the extent that rejected Annual CTA Allocations amount
to more than this Cap, the amounts that exceed the Cap will
be reassigned to CTAs in proportion to the amounts they
have rejected.
2.5.4.6 Accepted and Assigned CTA Storage Allocations: For amounts
---------------------------------------------
of capacity that a CTA may accept or have assigned, the CTA
will pay PG&E monthly, over the storage year, the revenue
requirement associated with accepted and assigned amounts
as a proportion of total core storage. CTAs must fill and
maintain accepted and assigned storage inventories on an
annual cycle as specified in the current tariff under
Schedule G-CT.
2.5.4.7 Core Procurement Core Storage Assignment: Amounts of core
----------------------------------------
storage not allocated to CTAs in accordance with Section
2.5.4.2 above, plus rejected CTA Core Storage Allocations
up to 1.64 Bcf, will be assigned to PG&E's Core Procurement
Department.
2.5.4.7.1 The cost of storage assigned to the Core Procurement
Department will be recovered through the procurement
portion of core customer bundled rates, subject to
balancing account treatment. All storage allocations
to the Core Procurement Department are to be treated
in the same manner as current Core Procurement
Department storage allocations in the CPIM.
2.5.4.7.2 The Core Procurement Department will fill and maintain
inventory for this assignment according to the terms
currently specified by the CPIM for amounts now
allocated to the Core Procurement Department.
2.5.4.8 Disposition of Rejected Core Storage Allocations Above 1.64
-----------------------------------------------------------
Bcf: Core storage inventory allocations rejected by CTAs
---
above 1.64 Bcf will be allocated to PG&E's at-risk
unbundled storage program.
2.5.4.9 Intra-Year Rules - Increase In Load: In August of each
-----------------------------------
year, based upon the CTA group contracted volumes for the
upcoming winter season using the Direct Access Service
Requests (DASRs) that have been processed to date, PG&E
will recalculate the pro rata CTA storage allocations and
compare this new calculation with the Annual Storage
Allocation calculated at the beginning of the current
storage season. If a CTA's allocated share of storage
inventory has increased by more than 100,000 therms, the
CTA must choose whether to accept an increased allocation
for any portion of the incremental change, in ten percent
(10%) increments. This election must be made between August
15 and September 1.
2.5.4.9.1 For amounts that the CTA accepts of these incremental
storage rights, gas in the Core Procurement
Department's storage account will be transferred to
the CTA storage account at a price that reflects a
weighted average Core Procurement (Schedule G-CP)
price for the months of April through October times an
injection schedule for the Core Procurement Department
(Schedule G-CT will be modified in this way for all
gas-in-storage transactions). The CTA will also pay
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the total cost of this storage capacity for that year
in payments over the remainder of the storage year.
2.5.4.9.2 For amounts that the CTA rejects of this offered
storage, Alternate Resources, in like amount, will be
required as described in Section 2.5.4.11 below.
Rejection of offered storage is subject to the Cap for
the current storage season. To the extent rejected
capacity exceeds the Cap during the intra-season
election, the right to reject storage will be pro
rated among those rejecting storage capacity at this
time.
2.5.4.10 Intra-Year Rules - Decrease In Load: If the mid-year
-----------------------------------
evaluation, described in Section 2.5.4.9 above, results in
a decrease of more than 100,000 therms in the amount of
storage inventory that would be allocated to a CTA, and the
CTA has accepted a storage allocation, the CTA must
transfer to the Core Procurement Department a share of its
reduced allocation in a proportion equal to the percentage
of its Annual Allocation that it accepted for the year. For
instance, consider a CTA whose Annual Allocation was
400,000 therms, and it accepted 300,000 therms, or
three-quarters of its allocation. If this CTA's mid-year
Allocation was 250,000 therms, three-quarters, or 112,500
therms of the 150,000 therm reduced allocation would be
transferred to the Core Procurement Department. The gas in
storage will also be transferred to Core Procurement
Department, which will pay the CTA for the storage and gas
on the same terms described in Section 2.5.4.9 above, to
the extent that the total rejected capacity has been
reduced.
2.5.4.11 CTA Certification of Alternate Resources: A CTA rejecting
----------------------------------------
all or part of a PG&E core storage allocation, must certify
to PG&E no less than ten business days before each winter
month that it has sufficient Alternate Resources in amounts
equal to the amounts of withdrawal capacity associated with
rejected storage. The certification is that the CTA has
contracts for the following resources or combination of
these resources which provide peak-day gas supplies
equivalent to that which would have been available from the
PG&E-allocated storage that the CTA has rejected. The
resources used as alternates in this certification cannot
duplicate any resources offered as replacements for winter
intrastate transmission capacity that the CTA may be
required to hold.
2.5.4.11.1 Contracted firm storage services from PG&E or from an
on-system CPUC-certificated independent storage
provider;
2.5.4.11.2 Contracted firm PG&E backbone capacity matched with an
equivalent quantity of contracted upstream gas supply,
and any necessary firm upstream pipeline capacity
(upstream gas supply can include a gas producer
contract, or a contract with an off-system
CPUC-certificated gas utility or independent storage
provider); and/or
2.5.4.11.3 Third-party peaking supply arrangements, where that
supply is backed up by contracts under Section
2.5.4.11.1 or 2.5.4.11.2 above.
2.5.4.12 Release and Indemnification of PG&E: Any CTA that elects to
-----------------------------------
reject all or a portion of its core storage allocation
shall enter into an agreement with
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PG&E releasing PG&E from any and all liability associated
with that CTA's rejection of its core storage allocation.
In this agreement, the CTA shall be required to indemnify
PG&E for any and all losses, including direct and
consequential damages, that arise (i) from any
representation in that CTA's certification which turns out
to be inaccurate or (ii) from any failure of its Alternate
Resources to perform as compared to the resources which
would have been available from the PG&E-allocated core
storage had this storage not been rejected by the CTA.
2.5.5 Term: This unbundling of core storage for CTAs will be effective
upon the effective date of the tariffs implementing this
Settlement Agreement provision. If this date is after December 1,
2000, then no intra-year elections may be made for the April
2000-March 2001 storage season as provided in Section 2.5.4.4.
This program will continue for the April 2001-March 2002 and for
the April 2002-March 2003 storage seasons. The provisions of this
program will be reconsidered as part of the post-Gas Accord
negotiations.
2.6 Separate Costs and Rates for Core Utility [Procurement] Services.
Treat Utility Core Procurement Departments as Any Other Utility
Customer
2.6.1 Summary of D.▇▇-▇▇-▇▇▇: The Commission recommends, to the extent
reasonable as determined in the cost-benefit phase, separating
the costs and rates for core utility services including core
procurement, transmission, storage, distribution, and balancing,
and treating the local distribution company core procurement
departments as a single customer for operational purposes, which
is subject to the same terms and conditions of service as other
customers. On PG&E's system, core customers are being treated
like any other customer, are clearly liable for OFO penalties,
and hub service revenues are not included in the CPIM. The
Commission recognizes that it is important to ensure that all
costs are assigned to the appropriate function. Additionally the
Commission states that when they have determined whether and the
extent to which various service components will be competitively
provided, the utilities will be able to implement separate rates
for those services, and to assure that no charges have been left
in any functional category by default. (p. 49 [#8], p. 62, p. 86,
Appendix C)
2.6.2 Current Brokerage Fee: A core brokerage fee of 2.4 cents per
decatherm was negotiated in the Gas Accord as a proxy for certain
costs directly related to PG&E's Core Procurement Department
functions and overheads. Under the Gas Accord, the brokerage fee
is subject to balancing account recovery and can be re-examined
if PG&E's market share drops to 80% (Gas Accord, ss.IV.H.1). The
parties reserved the right to propose other cost-based core cost
allocation and rate design changes in future BCAPs for
distribution rates and rate design (Gas Accord, ss.III.C.6.d.).
2.6.3 Resolution: The Parties agree the brokerage fee, and the method
of separating PG&E's Core Procurement Department costs this fee
addresses, will remain unchanged for the duration of this
Settlement Agreement. PG&E agrees to
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discuss this issue and to consider reevaluating the method of
allocating all procurement-related costs as part of PG&E's post-
Gas Accord negotiations.
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2.7 Provide Details of Completed Transactions
2.7.1 Summary of D.▇▇-▇▇-▇▇▇: The Commission believes that disclosure
of the transaction-specific details requested by parties is basic
and fundamental to an efficient market. In Conclusion of Law 17,
the Commission directs the utilities either to provide timely
information along the lines of the specific requests outlined in
this decision, or to find different ways to convey to shippers
information that they need to function effectively in the
marketplace without compromising confidentiality concerns. (pp.
▇▇- ▇▇, ▇▇▇ ▇▇, ▇▇▇ ▇▇, ▇▇▇▇▇▇▇▇ ▇)
2.7.2 Monthly Negotiated Contract Report: PG&E will continue to file a
monthly negotiated contract capacity report with the CPUC. This
reports lists the details, but not customer names, of all
negotiated capacity transactions for firm transportation,
as-available transportation, and storage. Negotiated arrangements
with affiliates or other Company departments are identified.
2.7.3 Resolution: Parties agree that the other provisions of this
Settlement Agreement, including Sections 2.2.3, 2.2.4, 2.7 and
2.8 of this Settlement Agreement, as well as the OFO Settlement
Agreement (filed October 22, 1999), should provide sufficient
information on transactions to the market and shippers to enhance
market liquidity and efficiency. Parties also agree that no
further litigation of this issue is needed in I.▇▇-▇▇-▇▇▇.
2.8 Establish a Secondary Market [Trading System] via a Utility Electronic
Bulletin Board
2.8.1 Summary of D.▇▇-▇▇-▇▇▇: Participation in the secondary market
transactions through a mandatory Electronic Bulletin Board is
consistent with the Commission's goals of enhancing market
efficiency, preventing anti-competitive behavior, and providing
additional competitive tools to the marketplace. Considering that
all secondary market transactions will need to be confirmed
through the utility, the Commission believes the utility should
be required to provide the electronic bulletin board. However,
the Commission wants to understand the costs of providing such a
service before determining whether to require its provision. (p.
79, FoF 38, Appendix C)
2.8.2 Current Secondary Market Trading: Secondary market capacity
trading is currently done on a voluntary basis through private
transactions. There is no facilitating electronic platform
currently available to the northern California market, other than
a posting section on PG&E's INSIDEtracc. If parties to a capacity
transaction want to change billing and nomination responsibility,
the assignment is reported to PG&E so the change can be made and
a new authorized nomination number can be provided.
2.8.3 Electronic Trading System Provisions: PG&E will facilitate a
voluntary and anonymous secondary market trading system for firm
backbone transmission
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capacity as part of its sole-source contract with ALTRA, and
subject to the terms of that contract. The following provisions
will apply:
2.8.3.1 Firm transmission capacity by path will be included on the
electronic trading platform.
2.8.3.2 ALTRA and PG&E will establish the process for reporting
assignments, and ALTRA will provide the screens and trading
platform.
2.8.3.3 ALTRA will notify PG&E of the capacity assignment upon
completion of a trade and PG&E will adjust its records
accordingly and issue a new authorized nomination number to
the assignee.
2.8.3.4 ALTRA will post on its electronic trading platform a
summary of the completed transactions, listing the amount
of capacity, the path (for transmission), transaction price
and the term of the assignment. Customer names will not be
provided.
2.8.4 Trading Fees: A monthly subscription fee is required if the
customer does not already subscribe to ALTRA. A smaller fixed
subscription fee will be made available for those entities who
only want to use ALTRA for capacity trading, and not commodity
trading. ALTRA will charge a transaction fee to both the buyer
and seller. This fee will be capped, and any discounts made
available on a nondiscriminatory basis. PG&E will receive fifty
percent (50%) of the transaction fees to cover its ongoing costs
and services, and will record one-half of these monies as a
credit to the BCA to help offset the costs for implementing this
trading system. PG&E will include the specific fee provisions in
its tariffs pursuant to Section 1.7 above.
2.9 Provide Real-Time, Customer-Specific Usage Data
2.9.1 Summary of D.▇▇-▇▇-▇▇▇: The Commission believes that customer
access to real-time consumption data is consistent with its goals
of increased market efficiency and providing competitive tools.
Access to real-time data may help customers to better manage
their pipeline flows. The Commission considers the most promising
option going forward appears to be for the utilities to make
available to any customer, at the customer's expense, the
equipment, technology and training necessary for expanded
customer access to timely consumption information. The Commission
is interested in hearing from parties in the cost/benefit phase
of this proceeding what it would cost on a per-customer basis to
make such access generally available, as well as the specific
impediments to providing real-time available capacity updates.
(pp. 72-73, ▇▇▇ ▇▇ & ▇▇, ▇▇▇ ▇▇-▇▇, ▇▇▇▇▇▇▇▇ ▇)
2.9.2 Customer Options to Access Meter Data: Currently, about 900 of
the 1200 noncore customers have Automatic Meter Reading (AMR)
equipment, which PG&E "polls" via conventional phone lines once
per day in order to retrieve the customer's hourly usage for each
of the prior 24 hours. Since it takes about four to five hours to
gather this data from all the AMR-equipped meters, the cumulative
24 hour data is not available to these customers until around
7:00 a.m.
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the following morning through PG&E's INSIDEtracc and Pipe Ranger.
In addition, PG&E currently offers all customers options to
access their gas usage data through pulses (which can be
converted to usage), with the cost billed to the specific
customer per the provisions contained in Gas Rule 2.C, Special
Facilities.
2.9.3 Dial-In Access to AMR Data: PG&E may, depending on interest from
market participants, offer customers, or their agents, dial-in
access to PG&E's AMR meters. PG&E will survey market
representatives to determine this level of interest. Any such
dial-in access program would be subject to the following
provisions. This option would only be available for meters
equipped with both Mercury ECAT and AMR equipment. Equipment
upgrades would be provided at customer expense to allow this data
access option. The number of customer calls per meter would be
limited to two per day so that battery life is not severely
reduced. Also, no customer calls would be allowed between the
hours of midnight and 5:00 a.m., during which time PG&E is
calling the meter and downloading data for its use. PG&E would
establish a start-up fee and a monthly service fee, as well as
fees for other requests, such as changing an access password.
These fees will be estimated based on recovering the costs to
implement and maintain this program.
2.9.4 Internet Information on Meter Access Options: PG&E may, depending
on interest from market participants, create an Internet
accessible web page specifying customer options for accessing
their own meter data or pulses. Each option would generally
describe the types of meters involved, the type of data provided,
the frequency of the data, an estimated cost range for typical
installations, any related service fees, and other information
which could help customers perform a rough evaluation of these
options. PG&E contact phone numbers would be provided for
responding to questions and to specific requests. These options
should include:
. AMR access for noncore customers,
. Meter pulse data for all customers,
. Dial-in access to the meter,
. Pilot for noncore meter ownership for new facilities (per
Section 2.10.4 below), and
. Pilot for meter add-on devices (per Section 2.10.5 below).
2.9.5 Internet Access to Full AMR Data: PG&E may, depending on
interest from market participants, make available on its Pipe
Ranger Web site the AMR usage data for each hour of the prior
day's usage in addition to the 24-hour total now provided. Data
would be available about 7:00 a.m. in the morning for the prior
midnight to midnight period. PG&E does not consider this billing
quality data since missing data is filled in using estimation
processes. This option would only be available to those customers
with AMR equipment. Fees may be charged for this service based on
recovering the costs to implement and maintain this program.
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2.9.6 Resolution: Parties agree that all issues in this proceeding with
respect to the provision of real-time consumption data are
resolved for the term of this Settlement Agreement and need not
be litigated.
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2.10 Provide Competitive Metering Technologies
2.10.1 Summary of D.▇▇-▇▇-▇▇▇: For safety implications, the Commission
does not currently believe that it is an option to encourage the
cost or rate separation of meter reading or servicing, or of what
have been referred to as after-meter services. Distribution
utilities should continue to provide these services as part of a
bundled distribution service. The Commission views the
competitive provision of meters to be a promising option,
consistent with their goals of ensuring safe and reliable
service, as well as their objective of removing unnecessary
barriers to entry into various components of the natural gas
service market. This inquiry can include consideration of whether
or not the local distribution company should become the owner of
any meter that it installs. Any meter would have to meet
appropriate safety standards and utilize standardized information
protocols. (pp. 84-85, Appendix C)
2.10.2 Resolution: Consistent with obligations under existing law, PG&E
will install, read, remove, service, and maintain all gas meters
during the term of this agreement. As part of the pilot program
described below, a limited number of noncore customers may own
their own PG&E-approved meters, or may choose meters to be owned
by PG&E, for new meter installations. Further, also as a pilot
program, a limited number of customers may own an "add-on device"
to the PG&E-owned meter that allows the customer to access (and
thus read remotely) meter data at time intervals needed for the
customer's own purposes, or allows the customer to provide this
meter data to another party. The selection and installation of
this add-on device must also comply with established standards
and procedures.
2.10.3 Principles for Ownership of Meters and Add-On Devices: The
following principles provide the basis for the pilot ownership
programs and to help guide implementation.
2.10.3.1 All customer-owned meters and add-on devices will have to
meet appropriate standards of safety, accuracy and
reliability, as determined by PG&E.
2.10.3.2 Customer ownership of any meter or add-on device will not
interfere with PG&E's right to obtain current or additional
data from the meter. PG&E also reserves the right to
reconfigure the meter to improve PG&E's ability to obtain
current or additional data. For example, if PG&E chooses to
install automated meter reading (AMR) technology for a new
class of customers or a given portion of its service area,
PG&E shall be free to install that capability for all
customers of that category, whether or not such customers
had previously installed a customer-owned meter or meter
add-on device incompatible with the AMR technology to be
employed by PG&E.
2.10.3.3 Those customers that choose to own their own meters or
add-ons are responsible for the additional incremental
costs associated with such equipment.
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2.10.3.4 Nothing in this Settlement Agreement prevents PG&E from
continuing to offer its currently available meter and
meter-related products and services, or to propose new
meter-related products and services. Furthermore, nothing
in this Settlement Agreement requires Parties to support
any PG&E proposals to offer any such new meter or
meter-related products and services during the term of this
Settlement Agreement.
2.10.4 Pilot Program for Customer Meter Ownership and Meter Choice: The
following provisions apply to this pilot program for limited
meter ownership and choice of PG&E-owned meters.
2.10.4.1 Participation Limit: The pilot program is limited to the
-------------------
installation of 500 customer-owned meters per year. The
pilot program applies only to new meter installations at
noncore customer facilities, and does not apply to the
replacement of an existing PG&E-owned meter. PG&E at its
sole discretion may increase the cap on the number of
meters which can be owned by customers.
2.10.4.2 Limit on Meter Choice: The meter ownership pilot program is
---------------------
limited to customer ownership of meters approved by PG&E.
Nothing in this program requires PG&E to evaluate and/or
approve additional meters that are not already approved as
of the date of a Commission order approving this Settlement
Agreement, nor does anything in this program prevent PG&E
from removing currently-approved meters from the approved
list.
2.10.4.3 Cost Responsibility: Customers choosing to own their meter
-------------------
are responsible for incremental costs associated with their
meter that are incurred by PG&E. Incremental costs are
those costs beyond the costs that would have been incurred
by PG&E having installed and owned the most cost-effective
meter for that site. Costs for which customers may be
responsible could include, but are not limited to,
installation of the meter or additional equipment,
maintenance, call-out servicing, and any other incremental
transaction-based costs associated with their owning the
meter.
2.10.4.4 PG&E Access to Meter Data: PG&E has the right to obtain or
-------------------------
directly access any data available from the customer-owned
meter. PG&E may also add-on devices to a customer-owned
meter which do not interfere with the customer's use of
that meter. PG&E would pay the cost of such add-ons.
2.10.4.5 Advice Filing for Pilot: PG&E will prepare and submit an
-----------------------
advice filing to implement this pilot meter ownership
program, including tariff and fee provisions, consistent
with the terms of this Settlement Agreement. This filing
will be made as part of the submission discussed in Section
1.7 of this Settlement Agreement.
2.10.4.6 Term of Pilot: This pilot program is effective when the
-------------
CPUC-approved tariffs implementing this program are
effective, and will continue for the term of this
Settlement Agreement.
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2.10.4.7 Assessment of Pilot: One year prior to the completion of
-------------------
the program, PG&E will begin working with interested
parties to prepare a report assessing the pilot meter
ownership program. This assessment report, which will
include recommendations concerning the future of the
program, will be submitted to the CPUC six months prior to
the end of the pilot. The report will address, among other
things, whether the pilot program should be expanded, and
the disposition of all existing customer-owned meters if
the meter ownership pilot program is terminated.
2.10.5 Pilot Program for Customer Ownership of Meter Add-Ons: Subject
to the following terms and conditions, PG&E will allow a limited
customer ownership of add-on devices to PG&E-owned meters for
the purpose of accessing meter data at time intervals needed for
the customer's internal purposes, or for providing such data to
another party.
2.10.5.1 Participation Limit: This pilot program is limited to the
-------------------
installation of 1000 customer-owned meter add-on devices
per year. PG&E at its sole discretion may increase the cap
on the number of customer-owned meter add-on devices.
2.10.5.2 Meter Responsibility: Add-on devices will not adversely
--------------------
affect the safety, reliability and accuracy of PG&E's gas
meters, nor PG&E's ability to obtain any meter data. PG&E
remains responsible for installation, removal, service and
maintenance of the meters and the add-on devices. Customer
ownership of an add-on device will not prevent or interfere
with PG&E's ability to replace or reconfigure the meter.
2.10.5.3 Cost Responsibility: Customers will be responsible for the
-------------------
costs associated with add-on devices, including, but not
limited to, installation, maintenance, removal, and any
other transaction-based costs associated with that add-on
device.
2.10.5.4 Advice Filing for Pilot: PG&E will prepare and submit an
-----------------------
advice filing to implement this pilot meter add-on program,
including tariff and fee provisions, consistent with the
terms of this Settlement Agreement. This filing will be
made as part of the submission discussed in Section 1.7 of
this Settlement Agreement.
2.10.5.5 Term of Pilot: This pilot program is effective when the
-------------
CPUC-approved tariffs implementing this Settlement
Agreement are effective, and will continue for the term of
this Settlement Agreement.
2.10.5.6 Assessment of Pilot Program: One year prior to the
---------------------------
completion of the program, PG&E will begin working with
interested parties to prepare a report assessing the pilot
meter add-on program. This assessment report, which will
include recommendations for the future of the program, will
be submitted to the CPUC six months prior to the end of
this program. The report will address, among other things,
whether the pilot program should be expanded, and the
disposition of all existing customer-owned add-on devices
if the meter add-on pilot program is terminated.
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2.11 Provide Competitive Billing Options to Customers Similar to Those
Offered in the Electric Industry
2.11.1 Summary of D.▇▇-▇▇-▇▇▇: The Commission states that competing gas
and electric providers should be able to choose to provide a
consolidated ▇▇▇▇ for gas and electricity so that the customers
of such providers will not face duplicative charges for the
billing function. The Commission feels that it may be appropriate
for the natural gas utilities to provide billing options similar
to those currently offered on the electric side. The Commission
states that it should be just as possible for an electricity
provider to ▇▇▇▇ its customers for gas service as it would be for
a gas provider to ▇▇▇▇ for electric service. The Commission
includes this as a promising option for further study and wants
to examine cost system conversion and potential labor impacts
associated with providing competitive billing and other services
in the cost/benefit phase. (pp. 85-86, FoF 43, CoL 19, Appendix
C)
2.11.2 Current Billing Options: Currently, CTAs who sell gas to
residential and small commercial customers have three options
open to them. The first option is for the CTA to ▇▇▇▇ for the gas
commodity and have PG&E ▇▇▇▇ for gas transportation. This is
called separate billing. The second option is for the CTA to ▇▇▇▇
for both their gas service and PG&E's transportation service.
This option is called CTA consolidated billing. A third billing
option, PG&E consolidated billing, where PG&E bills for both its
transportation service and the CTA's commodity gas cost, is
currently available only for dual-commodity customers who also
participate in electric direct access. PG&E consolidated billing
for gas-only customers (including those customers that receive
separate gas and electric bills) will not be available until the
Billing Availability Date as defined in Section 1.8 above.
2.11.3 PG&E Consolidated Gas Billing: PG&E will provide a PG&E gas
consolidated billing option for gas-only customers by the Billing
Availability Date. This approach avoids unnecessary costs for
programming and manual processes which would still take one to
one-and-a-half years to complete, and then be disposed of once
the new billing system is operational. Once implemented, PG&E
reserves the right to charge CTAs for PG&E consolidated gas
billing services based on a methodology consistent with the
methodology then in effect for PG&E consolidated electric
billing.
2.11.4 Termination of Informational ▇▇▇▇ Requirement: If a CTA performs
CTA consolidated billing, PG&E is currently required to send the
customer an informational ▇▇▇▇. The Parties agree that the
requirement for an informational ▇▇▇▇ should be removed upon
implementation of this Settlement Agreement for those CTAs
receiving PG&E billing information via Electronic Data
Interchange (EDI) that agree in writing to present the requisite
PG&E-provided charges, ▇▇▇▇ inserts and customer protection
information in each end-user ▇▇▇▇. CTAs also agree to provide a
market-index commodity price (i.e., the Natural Gas Intelligence
Weekly Gas Price Index, first of the month publication, PG&E
Citygate, Bidweek) or the currently-required PG&E core
procurement price in each end-user ▇▇▇▇. The CTA shall annually
elect which commodity price to provide. The requisite information
to be presented in each end-user's ▇▇▇▇ will be addressed as
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part of the tariff process described in Section 1.7 above. In the
agreement between PG&E and the CTA, the CTA shall indemnify PG&E
for all direct and consequential damages, and the CTA shall
expressly agree to assume all liability associated with the CTA's
modification of, or failure to provide a customer with, any PG&E-
provided ▇▇▇▇ insert. Any disputes concerning the content of PG&E
provided ▇▇▇▇ inserts will be resolved by the Energy Division of
the CPUC. As part of its compliance filing set forth in Section
1.7, PG&E will include provisions specifying compliance
monitoring, cost responsibility, and enforcement measures. Any
such CTA agreements will be in effect for the term of this
Settlement Agreement, except that they will expire after (i) gas
consumer protection legislation becomes effective which includes
a provision authorizing the CPUC to enforce consumer protection
rules, and (ii) the CPUC adopts such rules, including a CTA
certification program.
2.11.5 Billing Credits for CTA-Consolidated Billing: The customer of a
CTA, which performs consolidated CTA billing, will get the
following avoided cost credit off their transportation rate as
long as PG&E no longer has to send them an informational ▇▇▇▇ per
Section 2.11.4 above. These credits will apply for both gas-only
customers and dual-commodity customers for the term of this
Settlement Agreement. If an Energy Service Provider (ESP) is also
a CTA and performs both gas and electric consolidated billing for
a dual-commodity customer, then that customer will receive the
CTA consolidated gas billing credit in addition to the applicable
electric credit for a dual-commodity customer.
($ per account per month)
Residential G-NR1 G-NR2
----------- ----- -----
Gas Billing Credit $0.71 $1.00 $1.00
2.11.6 Delivery of CTA Consolidated Gas Billing Credits: PG&E will
deliver credits to those customers receiving consolidated billing
services from their respective CTAs via checks sent to the
respective CTAs in whatever manner PG&E deems most
cost-effective, except that PG&E will deliver such checks on at
least a semi-annual basis. This process will continue for the
term of this Settlement Agreement, or until automation of the gas
credit process in the new billing system. Upon automation of the
gas credit process, credits will be included as a line item on
PG&E's customer-specific billing data provided to CTAs and shown
on their consolidated ▇▇▇▇ to these customers.
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Rule 601 et seq of the FERC Rules of Practice. Rule 408 of the Federal
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3. PROMISING OPTIONS ALREADY IN PLACE FOR PG&E
Parties agree that the following promising options identified in D.▇▇-▇▇-▇▇▇
do not need to be litigated for the PG&E system in I.▇▇-▇▇-▇▇▇, although
they may be otherwise negotiated or litigated for the post-Gas Accord
period. Through the Gas Accord, PG&E has already implemented these options
for the Gas Accord period.
3.1 Create Firm Tradable Intrastate Transmission Rights
3.1.1 Summary of D.▇▇-▇▇-▇▇▇: The Commission agrees that the creation
of firm, tradable intrastate transmission rights offers the hope
of improving efficiency through value-based pricing, as well as
providing individual shippers with greater certainty as to their
ability to move certain quantities of gas through the pipeline
system.
(pp. 12-14, ▇▇▇ ▇ & ▇, ▇▇▇ ▇, ▇, ▇, ▇▇▇▇▇▇▇▇ ▇)
3.1.2 Resolution: The path-based firm backbone transmission capacity
rights established by the Gas Accord continue to apply for
Northern California. These rights are fully tradable and
assignable, subject to the creditworthiness of the assignee.
3.2 Establish a Secondary Market for Intrastate Transmission Capacity
3.2.1 Summary of D.▇▇-▇▇-▇▇▇: Participation in the secondary market
transactions through a mandatory Electronic Bulletin Board is
consistent with the Commission's goals of enhancing market
efficiency, preventing anti-competitive behavior, and providing
additional competitive tools to the marketplace. The Commission
wants to understand the costs of providing such a service before
determining whether to require its provision. (p. 79, FoF 38,
Appendix C)
3.2.2 Resolution: A secondary market exists for PG&E's firm intrastate
transmission capacity rights. This Settlement Agreement
establishes an electronic trading platform for secondary market
transmission transactions pursuant to Section 2.8 above.
3.3 Place the Utility At Risk for Unused [Transmission] Resources
3.3.1 Summary of D.▇▇-▇▇-▇▇▇: The Commission refers to the fact that
PG&E's shareholders are at risk for "stranded" costs associated
with intrastate transmission in a table. (p. 12)
3.3.2 Resolution: The Gas Accord places PG&E at risk for recovery of
transmission facility costs, and the rates associated with these
costs are fixed for the Gas Accord period. These at-risk
provisions continue to apply. However, this Settlement Agreement
does not predetermine how risk will be allocated following the
Gas Accord.
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3.4 Create Firm, Tradable Storage Rights
3.4.1 Summary of D.▇▇-▇▇-▇▇▇: The Commission believes there would be
more efficient use of the hard-to-find gas storage resources if
individual shippers and customers could bid for firm storage
access rights. In addition, the local distribution company will
be motivated to pursue more complete utilization of its storage
assets if its shareholders bear the risk for cost recovery. If
accompanied by an active secondary market, the bidding and
trading of storage rights should lead to pricing that reflects
demand. (pp. 23-24, ▇▇▇ ▇, ▇▇▇ ▇, ▇▇▇▇▇▇▇▇ ▇)
3.4.2 Resolution: The Gas Accord assigned PG&E's existing firm gas
storage capacity rights to core procurement, pipeline balancing
and an unbundled storage program. Annual open seasons are held
under the unbundled storage program, with negotiated deals at
other times. The acquirers of firm storage capacity can sell that
capacity on the secondary market, as can core procurement
entities holding firm storage capacity, subject to the
creditworthiness of the assignee.
3.5 Establish a Secondary Market For Intrastate Storage Capacity
3.5.1 Summary of D.▇▇-▇▇-▇▇▇: The Commission anticipates that the
existence of an active secondary market for storage would reduce
a utility's ability to increase its storage revenues in an unfair
manner. Shippers should be more willing to acquire storage rights
when they know they are able to sell unused capacity on the
secondary market. Participation in the secondary market
transactions through a mandatory Electronic Bulletin Board is
consistent with the Commission's goals of enhancing market
efficiency, preventing anti-competitive behavior, and providing
additional competitive tools to the marketplace. The Commission
wants to understand the costs of providing such a service before
determining whether to require its provision.
(p. 24, FoF 38, Appendix C)
3.5.2 Resolution: As with firm transmission capacity, firm storage
rights are already tradable and assignable under the provisions
of the Gas Accord, subject to the creditworthiness requirements.
Parties agree that no further action is needed on the PG&E system
for trading storage rights.
3.6 Place the Utility At-Risk for Unused [Storage] Resources
3.6.1 Summary of D.▇▇-▇▇-▇▇▇: The Commission requests the parties to
consider the costs and benefits related to creating a system of
tradable storage rights in Southern California that places the
utility at risk for unused resources and preserving such a market
in Northern California beyond the period of the Gas Accord.
(pp. 20-24, Appendix C)
3.6.2 Gas Accord At-Risk Requirements: The Gas Accord places PG&E at
risk for recovery of its storage facility costs. The major
portion of the storage (32.8 Bcf) is assigned to core customers
to ensure reliability of service. The core is obligated to pay
these costs. However, this Settlement Agreement allows Core
Transport
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Agents (CTAs) to provide reliability through other means and
avoid payment of their share of these costs. Another portion of
storage (2.2 Bcf) is assigned to pipeline balancing. These costs
are included in the backbone transmission rates, which are at-
risk for cost recovery. The feasibility of adding more storage
assets to this service is one of the issues for the OFO Forum, as
provided in the Gas OFO Settlement, filed October 22, 1999 in
I.▇▇-▇▇-▇▇▇.
The remaining portion of storage (4.7 Bcf) is assigned to a fully
at-risk unbundled storage program, where firm and negotiated
storage services are offered by PG&E's Golden Gate Market Center.
3.6.3 Resolution: These at-risk provisions for storage continue to
apply, as modified by this Settlement Agreement. However, this
Settlement Agreement does not predetermine how risk will be
allocated following the Gas Accord period.
3.7 Separate Utility Hub Services From Procurement Functions
3.7.1 Summary of D.▇▇-▇▇-▇▇▇: The Commission would like to separate hub
services, where possible, from the procurement function to
eliminate the possibility of a conflict of interest affecting the
two functions. (pp. 48-49, CoL 10, Appendix C)
3.7.2 Resolution: The current rules and protocols provide separation of
PG&E's Core Procurement Department from PG&E's utility hub
services for the term of the Gas Accord. This issue may be
revisited during the post-Gas Accord negotiations.
3.8 Unbundle Utility Interstate Capacity Costs for Core Customers
3.8.1 Summary of D.▇▇-▇▇-▇▇▇: The Commission recommends the unbundling
of interstate capacity costs for SoCalGas, which may enhance the
opportunities for competition for core customers, as marketers
search for ways to beat SoCalGas' costs for inter-state
transportation. PG&E and SDG&E have already unbundled such costs.
(p. 49 [#4], pp. 60-61, FoF 31, Appendix C)
3.8.2 Resolution: PG&E unbundled these costs as part of the Gas Accord.
This unbundling was approved in D.▇▇-▇▇-▇▇▇, dated December 4,
1997.
3.9 Eliminate Core Subscription Service
3.9.1 Summary of D.▇▇-▇▇-▇▇▇: The Commission recommends to eliminate
the core subscription by April 1, 2001, and require that any
noncore customer who prefers to continue procurement from local
distribution companies after that date to take and pay for core
service. (p. 49 [#7], pp. 63-64, Appendix C)
3.9.2 Resolution: The Gas Accord, as approved in D.▇▇-▇▇-▇▇▇, phases
out core subscription by March 1, 2001. Parties agree that no
further action is needed on the PG&E system.
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4. PROMISING OPTIONS AND OTHER ISSUES WHICH ARE NOT TO BE LITIGATED PENDING
FURTHER SETTLEMENT DISCUSSIONS
4.1 Develop Clear Procedures for Allocating [Firm] Capacity
4.1.1 Summary of D.▇▇-▇▇-▇▇▇ issued November 18, 1999: This decision
resolved the investigation into PG&E's bidding behavior in the
Gas Accord open season auction. The Commission finds that PG&E
abided by all the rules in place at that time and "that the UEG
did not behave in an anti-competitive manner warranting penalty.
The auction procedures should be reformed to further limit the
ability of any single entity to unduly influence the market."
(Mimeo, p. 22) The Commission also notes that "[F]urther
discussion of potential reforms to auction rules for intrastate
transmission capacity and for sales in the secondary market may
take place within Investigation ▇▇-▇▇-▇▇▇." (Mimeo, p. 25,
Ordering Paragraph 2)
4.1.2 Resolution: PG&E does not plan on conducting any firm capacity
open seasons before the end of the Gas Accord period. PG&E and
the Parties will re-examine the issue of open season rules in the
process of negotiating a post-Gas Accord settlement. Parties
agree that this issue does not need to be litigated or resolved
as part of I.▇▇-▇▇-▇▇▇ or the current Settlement Agreement.
4.2 Revise PG&E's Transmission Interconnection Policy, Terms and
Conditions (Not an Appendix C Item)
4.2.1 Gas Rule 27 Committee: This issue, which includes PG&E's proposed
Gas Rule 27, is under consideration by a committee of the
Parties. The objective is to resolve this issue through
settlement, and perhaps a separate application.
4.2.2 Resolution: Parties agree that these issues do not need to be
litigated or resolved as part of I.▇▇-▇▇-▇▇▇ or the current
Settlement Agreement.
4.3 Revise PG&E's Electric Generation Rate Design (Not an Appendix C Item)
4.3.1 Resolution: The Parties agree not to litigate issues related to
Public Utilities Code Section 454.4 in I.▇▇-▇▇-▇▇▇. The Parties
also agree that PG&E's Biennial Cost Allocation Proceeding
(BCAP), and not I.▇▇-▇▇-▇▇▇, is an appropriate proceeding in
which to address PG&E's electric generation cost allocation and
rate design issues in I.▇▇-▇▇-▇▇▇. PG&E commits to work with the
BCAP parties to attempt to settle these issues.
4.4. Review PG&E's Local Transmission Reliability, Design Standards and
Curtailment Provisions (Not an Appendix C Item)
4.4.1 Resolution: Parties agree that issues related to PG&E's local
transmission reliability, design standards and local curtailment
provisions will be negotiated
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separately, and will not be litigated with respect to PG&E as
part of I.▇▇-▇▇-▇▇▇ or resolved in this Settlement Agreement.
4.5 Investigate Mechanisms to Reduce the Costs of Transmission Service for
Noncore Customers Connecting To or Located Close To PG&E's Backbone
Transmission Facilities (Not an Appendix C Item)
4.5.1 Resolution: Parties agree that issues related to "direct
connects," and/or limited use of PG&E's local transmission
system, between a customer's facility and PG&E's backbone
facilities will be negotiated separately, and will not be
litigated with respect to PG&E as part of I.▇▇-▇▇-▇▇▇ or resolved
in this Settlement Agreement.
5. PROMISING OPTIONS WHICH WERE SETTLED IN THE OFO SETTLEMENT AGREEMENT
5.1 Examine Strategies for Devoting More Assets to PG&E Balancing
5.1.1 Summary of D.▇▇-▇▇-▇▇▇: The Commission states that it is clear
that shippers need to be better-equipped to anticipate and
respond to OFOs. It's logical to assume that if PG&E had more
storage capacity set aside to support its balancing efforts, it
would have greater ability to smooth out fluctuations in system
balancing without calling OFOs or undertaking curtailments. The
Commission considers asking PG&E to identify the incremental cost
of expanding balancing services in the next phase and suggests
all interested parties to address the economics of this step.
(pp. 32-33, FoF 15, CoL 6, Appendix C
5.1.2 OFO Forum: This issue will be considered by the OFO Forum in
accordance with Section 2.1.3.7 above.
5.1.3 Balancing Study: PG&E agrees to provide the balancing study to
all parties participating in the OFO Forum no later than March 7,
2000, even if the date for filing testimony is extended.
5.1.4 Resolution: Parties agree that this issue does not need to be
litigated in I.▇▇-▇▇-▇▇▇ and that the Forum is open to all
storage operators on the PG&E system, as well as customers,
shippers and consumer representatives.
5.2 Implement Targeted Operational Flow Orders
5.2.1 Summary of D.▇▇-▇▇-▇▇▇: The Commission wants to explore targeted
OFOs along with other similar reforms in the cost/benefit phase.
They believe even though it's possible that some customers might
respond to a targeted request by shifting excess gas to other
customers, it may also improve the system balance. (p. 41, p. 50
[#10], ▇▇▇ ▇▇, ▇▇▇ ▇, ▇▇▇▇▇▇▇▇ ▇)
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5.2.2 Resolution: The OFO Settlement provides specific procedures for
implementing customer-specific or targeted OFOs. No further
litigation is needed.
5.3 Provide Pipeline Operator Demand Forecasts Broken Down by Customer
Class
5.3.1 Summary of D.▇▇-▇▇-▇▇▇: The Commission is not persuaded that
disaggregating demand forecast information will create a
disadvantage for any customer, including the core. Furthermore,
the Commission does not believe that any particular customer
would have an incentive to lessen the reliability or precision of
its communications with the pipeline operator if they were
provided the demand forecasts. (pp. 79-84, FoF 41, Appendix C)
5.3.2 Resolution: The OFO Settlement Agreement specifies that PG&E will
provide customer class demand data with a three-day lag, as
agreed to by those Parties. No further litigation is needed.
6. NO ISSUES REMAIN TO BE LITIGATED IN I.▇▇-▇▇-▇▇▇
Parties agree that there are no issues of material fact or promising
options which need litigating in I.▇▇-▇▇-▇▇▇, provided the Commission
approves this Settlement Agreement pursuant to its conditions. If
Commission approval is conditional or modifies the Settlement Agreement,
Parties reserve the right to seek hearings on any or all issues otherwise
covered by this Settlement Agreement.
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Rule 601 et seq of the FERC Rules of Practice. Rule 408 of the Federal
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