CPUC Promising Gas Options
I.99-07-003

Comprehensive Gas OII
Settlement Agreement For
Southern California Gas Company
And San Diego Gas & Electric Company

April 17, 2000

I.	    INTRODUCTION	1
II.	PROVISIONS OF SETTLEMENT AGREEMENT ORGANIZED BY PROMISING OPTIONS LISTED IN APPENDIX C TO D.99-07-003	8

1.	INTRASTATE TRANSMISSION	8
1.1	Create Firm Tradable Intrastate Transmission Rights	8
1.2	Establish a Secondary Market for Intrastate Transmission Capacity	20
1.3	Place the Utility At Risk for Unused [Transmission] Resources	22
1.4	Establish Hector Road as a Delivery Point on the SoCalGas System	23
1.5	Publish SoCalGas Windowing Criteria in Tariffs.  [Includes Implementing Targeted Operational Flow Orders]	25

2.	   STORAGE	29
2.1	Create Firm, Tradable Storage Rights	29
2.2	Establish a Secondary Market For Intrastate Storage Capacity	35
2.3	Place the Utility At-Risk for Unused [Storage] Resources	38

3.	BALANCING	40
3.1	Examine Structural Means For SoCalGas To Provide Balancing Services Without Drawing On Core Assets.	40
3.2	Cost and Rate Separation for Balancing Services [Self-Balancing Option]	41
3.3	Electronic Trading of Imbalances [Including Rights]	45

4.	HUB SERVICES	50
4.1	 Separate Utility Hub Services from Procurement Functions	50

5.	CORE PROCUREMENT	52
5.1	Re-examine Utility Role in Core Procurement Once a Specified Competitor Market Share Has Been Achieved	52
5.2	Eliminate Core Aggregation Transportation Thresholds after Adoption of Consumer Protection Measures	53
5.3	Unbundle Utility Interstate Capacity Costs for Core Customers	54
5.4	Unbundle Utility Storage Costs for Core Customers [Served by CTAs]	57
5.5	Eliminate Core Subscription Service	62
5.6	Separate Costs and Rates for Core Utility [Procurement] Services.  Treat Utility Core Procurement Departments as Any Other Utility Customer	63

6.	INFORMATION	63
6.1	Provide Real-Time, Customer-Specific Usage Data	64
6.2 	Provide Details of Completed Transactions	66
6.3	Establish a Secondary Market [Trading System] via a Utility Electronic  Bulletin Board	68
6.4	Provide Pipeline Operator Demand Forecasts Broken Down By Customer Class	69

7.	REVENUE CYCLE SERVICES	69
7.1	 Provide for Competitive Metering Technologies	70
7.2	Provide Competitive Billing Options to Customers Similar to Those Offered in the Electric Industry	74
III.	NO ISSUES REMAIN TO BE LITIGATED IN I.99-07-003	76

APPENDICES

Appendix A:  Identification and Map of SoCalGas Backbone Transmission Facilities

Appendix B:  Description of SoCalGas Firm Backbone Transmission Rights and Capacities

Appendix C:  OFO Event Monitoring and OFO Forum Provisions

Appendix D:  Description of Operating Information to Be Made Available

Appendix E:  Description of Pooling Service

Appendix F:  Core Load Forecasting Model

CPUC Promising Gas Options I.99-07-003
Comprehensive Gas OII Settlement Agreement
For Southern California Gas Company
And San Diego Gas & Electric Company

I.	    INTRODUCTION
1.1	Purpose:  The purpose of this Comprehensive Gas OII Settlement Agreement for Southern California Gas Company (“SoCalGas”) and San Diego Gas & Electric Company (“SDG&E”) (“Settlement Agreement”) is to address the most promising options and other issues presented in Investigation (I.)99-07-003.  Specifically, the goal of this Settlement Agreement is to resolve all SoCalGas and SDG&E issues that would otherwise be litigated in I.99-07-003.
1.2	Parties:  This Settlement Agreement is entered into by the Settlement Parties (“Parties”), as identified by their attached signatures.  Parties agree, subject to Section 1.12 of this Part I, to actively support this Settlement Agreement in I.99-07-003 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.  For purposes of consistency with Pacific Gas and Electric Company (“PG&E”), marketers in the SoCalGas and SDG&E core aggregation transportation (“CAT”) program who have heretofore been referred to as “CAT marketers” will be referred to as “CTAs” (an acronym for “Core Transport Agents”).
1.3	Background:  In Decision (D.)99-07-015, 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 February 8, 2000, Administrative Law Judge Andrea L. Biren directed parties to file a settlement of all or some of the issues in this docket as applied to SoCalGas and SDG&E by April 3, 2000.  This deadline was extended by the ALJ at the Prehearing Conference on April 11, 2000, to April 17, 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.99-07-003.  No issues require further litigation in this proceeding for SoCalGas or SDG&E, except with respect to some implementation details of the terms of this Settlement Agreement.  This Settlement Agreement provides for certain issues to be the subject of future proceedings at a specified times after the 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.  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.
	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 or makes its approval conditional on modifications, each party reserves the right to withdraw its support for the Settlement Agreement.
1.6	Cost Recovery:  SoCalGas and SDG&E will be allowed recovery in rates of the costs resulting from this Settlement Agreement as follows:
1.6.1	SoCalGas Costs:  SoCalGas is entitled to recover costs resulting from this Settlement Agreement as follows:
1.6.1.1	With respect to recovery of the costs of implementing the following Sections 1, 2, 3, 5.4, and 6.1.4 of Part II of this Settlement Agreement (referred to for purposes of this Section 1.6 of Part I as “capacity-related sections”), SoCalGas is authorized by Commission approval of this Settlement Agreement to recover in rates an additional $2.0 million, plus related franchise fees and uncollectibles, per year from the effective date of this Settlement Agreement until the effective date of a Commission decision re-establishing SoCalGas’ authorized margin after the expiration of the PBR period established for SoCalGas in D.97-07-054.  The $2.0 million per year will be prorated for any partial calendar year that this Settlement Agreement is in effect prior to the effective date of a re-established authorized margin for SoCalGas.  The revenue requirement of $2.0 million shall be allocated among customer classes on an equal cents per therm basis, using the Commission’s most recently-adopted forecast throughput by customer class, and included in volumetric rates for bundled service.  For the period from the effective date of this Settlement Agreement to the effectiveness of a new SoCalGas authorized margin, in addition to the $2.0 million annual amount described above, SoCalGas shall be entitled to retain any pooling service fees, imbalance fees, net revenues from the sale or purchase of gas beyond tolerances provided under balancing rules, or portion of rights trading fees it is entitled to retain under agreements with third-party providers of trading platforms.  However, if in any calendar year the total of $2.0 million per year (prorated for any partial year effectiveness) plus revenues from such fees and imbalance purchase/sales exceeds the actual revenue requirement associated with all implementation costs incurred by SoCalGas for such sections, SoCalGas shall refund in bundled volumetric rates on an equal cents per them basis the excess above $2.0 million (or prorated portion of $2.0 million for a partial calendar year).
SoCalGas shall be entitled to include the reasonably-incurred revenue requirement for performing the functions required by the “capacity-related sections” of this Settlement Agreement in the period after the current SoCalGas PBR period in its authorized margin to be established in the proceeding applicable to the period after the current SoCalGas PBR period.  No Party shall oppose SoCalGas’ recovery of reasonably-incurred costs to perform such functions in the period after the current SoCalGas PBR period.  In the proceeding to establish SoCalGas’ authorized margin for the period after its current PBR period, Parties may contest whether specific costs are reasonably incurred to perform the functions required by the “capacity-related sections” of this Settlement Agreement and the Commission may disallow costs it finds are not reasonably-incurred to perform such functions.
This Settlement Agreement does not resolve for the period after December 31, 2002, the extent to which SoCalGas shall recover any costs authorized for recovery consistent with this section 1.6.1.1 through fees for services related to its transmission and storage services as compared to through bundled transportation rates, nor does it resolve whether, to what extent, or to which persons SoCalGas shall refund any such fees collected in that period.  These issues may be addressed by the Parties and the Commission in SoCalGas’ next PBR/Cost of Service proceeding or next BCAP.
1.6.1.2SoCalGas shall be entitled to recover the costs of implementing Sections 5.1, 5.2, 5.5, 5.6, 6.1.3, and 7 of Part II of this Settlement Agreement (referred to in this Section 1.6 of Part I as “retail” sections) and Section 5.3 of Part II (referred to in this Section 1.6 of Part I as the “core interstate” section), as follows:
SoCalGas shall not be entitled to any increase in its authorized margin for the period from the effective date of this Settlement Agreement until the effective date of a Commission decision re-establishing SoCalGas’ authorized margin after the expiration of the PBR period established for SoCalGas in D.97-07-054, provided that if the Commission approves, in a separate application, any fees or charges applicable to CTAs associated with automated direct access service requests, account management systems, utility consolidated billing, or the meter ownership/add-on pilot program, then SoCalGas may retain the revenues generated by those fees or charges prior to the effective date of a decision re-establishing SoCalGas’ authorized margin.
For the period after the current SoCalGas PBR period, SoCalGas shall be entitled to include in rates effective with the next re-establishment of SoCalGas’ authorized margin the revenue requirement associated with capital investments incurred as a result of the “retail” and “core interstate” sections.  No Party shall oppose SoCalGas’ recovery in the period after the current SoCalGas PBR period of the revenue requirement associated with capital costs incurred to perform such functions, and these costs shall be deemed reasonable. This Settlement does not adopt a specific method for allocating these costs in future proceedings, except that retail market implementation costs that are incurred to serve core customers or CTAs should not be allocated directly to noncore customers.  The Parties agree, however, that inclusion of these costs in EPMC scaling or another mechanism in order to allocate A&G or General Plant overhead costs to all customer classes is not precluded by this Settlement.  Proposals by SoCalGas to recover in rates, effective with the next re-establishment of its authorized margin, the revenue requirement associated with additional capital investments incurred after the current PBR period as a result of the “retail” and “core interstate” sections may be contested by the Parties as not reasonably necessary to perform the functions required by those Sections.   SoCalGas may request recovery in rates effective with the next re-establishment of SoCalGas’ authorized margin of expenses for that period to be incurred as a result of the “retail” and “core interstate” sections, and Parties may oppose such recovery.

1.6.2	SDG&E Costs:  SDG&E will be allowed recovery in rates of the cost of implementing this Settlement Agreement as follows:
1.6.2.1	SDG&E shall not be entitled to any increase in authorized revenue requirement as a result of the “capacity-related sections” for the period from the effective date of this Settlement Agreement until the effective date of a Commission decision re-establishing SDG&E’s authorized revenue requirement after the expiration of the distribution PBR period established for SDG&E in D.99-05-030; provided, however, that if the Commission adopts and implements for SDG&E prior to the end of that period a firm, tradable intrastate transmission rights system on the SDG&E system or other measures related to gas transmission, storage or balancing beyond those required by this Settlement Agreement, SDG&E is not barred by this Settlement Agreement from seeking recovery of additional costs.
SDG&E shall be entitled to recover in the period after the current SDG&E distribution PBR period the reasonably-incurred revenue requirement for performing any functions made necessary by the “capacity-related sections” of this Settlement Agreement.  No Party shall oppose SDG&E’s recovery of reasonably-incurred costs to perform such functions in the period after the current SDG&E distribution PBR period.  In the proceeding to establish SDG&E’s authorized revenue requirement for the period after its current distribution PBR period, Parties may contest whether specific costs are reasonably incurred because of the “capacity-related sections” of this Settlement Agreement and the Commission may disallow costs it finds are not reasonably-incurred because of such Sections.
1.6.2.2	SDG&E shall be entitled to recovery of costs related to implementation of “retail” sections as follows:  SDG&E shall not be entitled to any increase in its authorized revenue requirement for the period from the effective date of this Settlement Agreement until the effective date of a Commission decision re-establishing SDG&E’s authorized revenue requirement after the expiration of the distribution PBR period established for SDG&E in D.99-05-030, provided that if the Commission approves, in a separate application, any fees or charges applicable to CTAs associated with automated direct access service requests, account management systems, utility consolidated billing, or the meter ownership/add-on pilot program, then SDG&E may retain the revenues generated by those fees or charges prior to the effective date of a decision re-establishing SDG&E’s authorized revenue requirement.
For the period after the current SDG&E distribution PBR period, SDG&E shall be entitled to include in rates effective with the next re-establishment of SDG&E’s authorized revenue requirement the revenue requirement associated with capital investments incurred as a result of the “retail” sections.  No Party shall oppose SDG&E’s recovery in the period after the current SDG&E distribution PBR period of the revenue requirement associated with capital costs incurred to perform such functions, and these costs shall be deemed reasonable.  Proposals by SDG&E to recover in rates, effective with the next re-establishment of its authorized margin, the revenue requirement associated with additional capital investments incurred after the end of the current PBR period as a result of the “retail” sections may be contested by the Parties as not reasonably necessary to perform the functions required by those Sections.  SDG&E may request recovery in rates effective with the next re-establishment of SDG&E’s authorized revenue requirement of expenses for that period to be incurred as a result of the “retail” sections, and Parties may oppose such recovery.

1.6.3	The Gas Industry Restructuring Memorandum Accounts (“GIRMAs”) requested by SoCalGas (in Advice Letter 2895) and by SDG&E (in Advice Letter 1185-G), if approved, shall be modified retroactively to their establishment to be consistent with the terms of this Settlement Agreement.  This Settlement Agreement does not limit the ability of SoCalGas or SDG&E to seek or the Commission to grant memorandum account treatment for costs of programs or activities outside the scope of this Settlement Agreement.

1.7	Implementation and Term:  In general, the effective date of this Settlement Agreement is the later of:  (a) ninety (90) days after the issuance of a Commission decision approving it, or (b) October 1, 2000.  However, this Settlement Agreement provides for later implementation dates for certain of its provisions.  Any implementation dates later than the effective date of this Settlement Agreement are stated in specific sections of this Settlement Agreement.  This Settlement Agreement terminates on August 31, 2006.  In addition, this Settlement Agreement provides that certain provisions shall terminate prior to August 31, 2006.  Any termination date for a specific provision earlier than August 31, 2006, is stated in relevant specific sections of this Settlement Agreement.

1.8	Post-Term Period:  No later than October 31, 2005, SoCalGas shall file an application with the Commission proposing terms, conditions, and rate structures for transmission and storage services for all customer classes, to be effective as of September 1, 2006, after the term of this Settlement Agreement expires.  SoCalGas shall enter into discussions with all interested persons regarding the subject matter of this application no later than the date of its filing.

1.9	Effect of this Settlement Agreement on Existing Contracts for Service by SoCalGas and SDG&E:  This Settlement Agreement does not by its own terms alter, modify, terminate or abrogate any contract for utility service by SoCalGas or SDG&E, or California Producer Gas Access Agreement, entered into as of April 17, 2000, and that has been approved by the Commission, except as specifically set forth in this Settlement Agreement.  This Settlement Agreement does not alter the rights of parties to such contracts without the written consent of the parties to such contracts.  SoCalGas and SDG&E shall not use this Settlement Agreement as a basis for altering, modifying, terminating or abrogating any such contract without the consent of the other party to the contract.  With respect to long-term transportation contracts with SoCalGas existing as of the filing of this Settlement Agreement, customers under any such contracts that have provisions that provide specific treatment for deliveries at particular SoCalGas receipt points shall have the right to elect prior to the initial open season for backbone transmission service to receive firm backbone capacity at those receipt points sufficient to prevent the customers from losing the benefit of the bargain in such contracts.  The treatment of Wheeler Ridge Access Agreements is specifically addressed in Section 1.1 of Part II of this Settlement Agreement.  California Producer Gas Access Agreements under which historic deliveries have been made over North Coastal and Line 85 receipt points shall not be modified in any way during the term of this Settlement Agreement without the written consent of all parties to each such agreement (See also Appendix B). 

1.10	Effect of Settlement Agreement on Prior Commission Decisions:  This Settlement Agreement, once approved by the Commission, shall modify the terms of prior Commission decisions only to the extent that the implementation of the terms of this Settlement Agreement requires deviation from the terms of such prior Commission decisions.

1.11	Impact of Settlement Agreement on Allocation between Core and Noncore Classes:  It is the intention of the Parties that this Settlement Agreement, exclusive of the provisions of the Settlement Agreement regarding SoCalGas’ Core Interstate Capacity Unbundling, result in almost no cost shift between core and noncore customer classes.  The provisions of this Settlement Agreement shall be interpreted by the Commission in a manner consistent with this intention.

1.12	Prior Settlement:  Some of the Parties to this Settlement Agreement signed a settlement filed on December 27, 1999, in I.99-07-003 referred to as the “Interim Settlement.”  This Settlement Agreement incorporates many of the provisions of the Interim Settlement, but is more consistent with the promising options as identified by the Commission in D.99-07-015.  To the extent that the Commission finds the Interim Settlement insufficiently consistent with the promising options identified by the Commission in D.99-07-015 or otherwise finds it unacceptable, the Parties to this Settlement Agreement who signed the Interim Settlement support the full implementation of this Settlement Agreement
II.	PROVISIONS OF SETTLEMENT AGREEMENT ORGANIZED BY PROMISING OPTIONS LISTED IN APPENDIX C TO D.99-07-003
1.	INTRASTATE TRANSMISSION
1.1	Create Firm Tradable Intrastate Transmission Rights
1.1.1	Summary of D.99-07-015:  The Commission agrees that the creation of firm, tradable intrastate transmission rights for SoCalGas offers the hope of improving efficiency and fostering increased competition, as well as providing individual shippers with greater certainty as to their ability to move certain quantities of gas through the pipeline system.  The Commission does not see the need to create such rights on the SDG&E system at this time.  (pp. 12-14, FoF 1 & 2, CoL 1, 2, 5, Appendix C) 

1.1.2	Current Status:  Firm, tradable intrastate transmission rights do not currently exist on the SoCalGas or SDG&E systems.

1.1.3	Resolution:  This Settlement Agreement establishes a system of firm, tradable intrastate backbone transmission rights on the SoCalGas system, as described below.  This Settlement Agreement does not establish a system of firm, tradable intrastate transmission rights on any portion of SDG&E’s gas transmission system.  However, nothing in this Settlement Agreement prohibits the Commission from adopting a system of firm, tradable transmission rights on the SDG&E system during the term of this Settlement Agreement.  Transportation-only gas customers of SDG&E must obtain intrastate backbone transmission on the SoCalGas system effective October 1, 2001, in the same manner as transportation-only customers on the SoCalGas system.

1.1.3.1	General description:  This Settlement Agreement establishes a system of firm, tradable intrastate transmission rights on the “backbone” transmission system of SoCalGas, effective October 1, 2001.  Backbone transmission facilities are specifically listed in Appendix A to this Settlement Agreement.  Transmission facilities other than backbone transmission facilities are designated as “local transmission”.  Backbone transmission rights are defined as the firm right to have SoCalGas receive gas at a specific receipt point and have SoCalGas redeliver the gas at any point of interconnection of its backbone transmission system with its local transmission system or distribution system, or to any SoCalGas storage field.  Backbone transmission rights are receipt point specific, not “path” specific as is the case under PG&E’s Gas Accord.  Firm backbone rights holders may also nominate gas to be delivered off-system at any other receipt point into the SoCalGas system, subject to certain terms and conditions.  This Settlement Agreement provides for the establishment of a specified quantity of firm backbone rights to be made available to the market for each receipt point.  Capacity from receipt points that may be available from day to day above the specified firm quantities may be marketed by SoCalGas on an interruptible basis.  There are also provisions for making specific backbone capacity available to wholesale customers and CTAs on the SoCalGas system.  This Settlement Agreement assigns to SoCalGas’ Gas Acquisition Department specific quantities of firm backbone rights at specific receipt points for use in serving core customers taking procurement service from SoCalGas, and provides a formula for the reduction of those assignments if the share of core procurement market served by SoCalGas declines.  Firm backbone transmission rights not allocated to SoCalGas’ Gas Acquisition Department, CTAs, or wholesale customers, will be made available in an open season process.  In the first two stages of the initial open season, existing end-use and wholesale customers will be allowed to participate based on their historical requirements.  Any creditworthy person will be allowed to participate in the third stage of the initial open season.  Participants may bid for a term anywhere from one year to the full remaining term of this Settlement Agreement, but in the third stage of the initial open season, SoCalGas will offer at least 20% of the capacity not contracted for in the first two stages for a term of one year only (to be offered again in subsequent annual open seasons).  The annual revenue requirement of the SoCalGas backbone transmission system is quantified by this Settlement Agreement on an embedded cost basis, unbundled from bundled transportation rates, and recovered solely through revenues from contracts for backbone transmission service.  The Settlement Agreement also provides for the manner of allocation of the local transmission revenue requirement between customer classes in bundled transportation rates.  This Settlement Agreement establishes a single “postage stamp” rate for backbone transmission capacity applicable to all receipt points based on a specified system load factor.  The postage stamp rate is subject to adjustment annual by the base rate PBR formula.  In the open seasons, parties can bid either a rate design with a 100% reservation charge or a rate design with 50% of the total rate in the reservation fee and 50% in a volumetric charge.  The 50/50 rate design will reflect a total rate that is a specified premium on the postage stamp rate.  Bids at the two rate designs for the same term will be treated equally in the award of backbone transmission rights.  SoCalGas can market firm rights not awarded in the open seasons through individually-negotiated contracts on a firm basis, and any capacity that may be available above the quantities established as firm in this Settlement Agreement on an interruptible basis.  The rate for individually-negotiated firm or interruptible contracts shall not exceed 120% of the applicable rate in the open season.  As provided in succeeding sections of this Settlement Agreement, holders of firm backbone transmission rights may trade (and then re-trade) them in a secondary market for any term and in any amount.   SoCalGas will be 100% at shareholder risk/reward for the recovery of the embedded cost of its backbone transmission system from backbone transmission service contract revenues.

1.1.3.2 Definition, cost, and rates for unbundled backbone transmission facilities:  The unbundled backbone transmission facilities consist of the numbered SoCalGas transmission lines and associated facilities listed in Appendix A to this Settlement Agreement and as shown on the map included in that appendix.  For purposes of this Settlement Agreement and all other Commission ratemaking during the term of this Settlement Agreement, the annual revenue requirement on an embedded cost basis for calendar year 2000 is established as $138.0 million for SoCalGas’ entire transmission system, and as $73.7 million for the backbone transmission system.  Transmission fuel will be recovered from transmission customers through an in-kind charge of 0.39% for volumes transported on the SoCalGas system.  The backbone transmission system embedded cost will escalate on January 1, 2001 and 2002 according to the annual indexing formula (inflation less productivity plus customer growth, with adjustment for any “Z factors”) adopted by the Commission for SoCalGas’ current base rate PBR in D.97-07-054.  Effective January 1, 2003, and thereafter for the term of this Settlement Agreement, it will escalate by whatever Commission-adopted PBR or attrition formula is generally applicable to SoCalGas’ base rates is in effect at the time.  The in-kind charge for transmission fuel is not subject to PBR escalation.  The rate for firm backbone transmission service with respect to all receipt points is calculated in this Settlement Agreement using a system firm capacity of 3500 MMcfd, a load factor of 79%, and a Btu content of gas of 1,016 Btu/mcf.  The use of a firm system capacity of 3500 MMcfd and a 79% load factor shall remain fixed for the term of this Settlement Agreement, but the 1,016 Btu factor may be revised with Commission approval during the term of this Settlement Agreement to reflect more current operating conditions.  The resulting firm backbone transmission rate using the cost for calendar year 2000 is a postage stamp rate of $.07191 per dth per year, which will carry a 100% reservation charge.  SoCalGas will also offer a rate design that has a 50% reservation charge and a 50% volumetric charge based on a postage stamp rate of $.07591 per dth per year.  All rates and ceilings on rates for backbone transmission service shall escalate consistently with the provisions stated above applicable to the annual revenue requirement associated with total transmission and backbone transmission.
As of October 1, 2000, the cost of backbone transmission rights on SoCalGas’ system held by SoCalGas and by SDG&E to serve their core procurement customers will be recovered through their monthly core procurement rates.  Backbone transmission cost may be an integral part of each utility’s procurement rate and need not be stated as a line item on bills separate from the rest of the procurement rate.  The inclusion of the backbone costs in the procurement rate shall not in and of itself alter the GCIM applicable to SoCalGas or the Gas Cost PBR applicable to SDG&E.
1.1.3.3 Definition of Receipt Point Capacities and Rights:  Backbone transmission rights are defined with respect to the receipt point into the SoCalGas system at which gas is received.  The details of the rights are included in Appendix B to this Settlement Agreement.  The wording of Appendix B is controlling over the summarization of its contents in this Section.  This Settlement Agreement defines the rights based on seven receipt points:  Blythe (Ehrenburg), Topock, North Needles, Hector Road, Wheeler Ridge (with two sets of defined rights), Line 85, and North Coastal.  When there is more than one pipeline or other source that might deliver gas to the SoCalGas system at a particular receipt point, the receipt point rights are defined in terms of primary and secondary access by upstream source.  The relative scheduling priority of firm rights by primary and secondary upstream source and interruptible transportation are described in Appendix B.  SoCalGas system operations require some minimum flowing supply be received at Blythe.  Therefore, as provided in Appendix B persons acquiring backbone rights at the Blythe receipt point must agree to be subject to SoCalGas’ right to issue an Operating Flow Order on any given day requiring them to actually deliver at Blythe on the succeeding day gas supplies up to 50% of their backbone capacity rights at Blythe.  In the event that an OFO is called for Blythe shippers, the OFO charges will apply, but any imbalance charges that may result will be waived.  In addition, to the extent that the Blythe OFO causes a monthly imbalance for the Blythe customers, Blythe customers will be allowed to carry the imbalance forward one month without any charges for doing so.  SoCalGas is obliged for the term of this Settlement Agreement to use all reasonable efforts to maintain the availability of the amount of firm backbone capacity at each receipt point as shown in Appendix B.  SoCalGas is not allowed any additional cost recovery to meet this commitment except pursuant to whatever PBR indexing or attrition mechanisms and mechanisms for catastrophic event costs are in place during the term of this Settlement Agreement.  This Settlement Agreement does not address under what conditions, if any, SoCalGas must expand its backbone capacity, or the treatment (such as rates, allocation of capacity, etc.) of any increase in backbone capacity that SoCalGas may construct.  These issues are left to the Commission to resolve at such time, if ever, as it chooses to resolve them.
1.1.3.4 Local Constraints and Service Interruption Credit:  Firm backbone transmission rights do not guarantee firm service on the local transmission or distribution systems.  SoCalGas will take whatever steps it determines are operationally necessary in the event a constraint on local transmission or distribution threatens service to customers.  This includes curtailment of noncore customers.  Section 1.5.4 of this Settlement Agreement provides for the involuntary diversion of noncore customer supplies on the system if necessary to avert interruption of service to core customers, with a $25 per dth fee for involuntarily diverted gas to be paid by the customers receiving such gas, and for compensation to the customers whose gas was involuntarily diverted.   In light of the all of the provisions of this Settlement Agreement, SoCalGas’ existing Service Interruption Credit guarantee is no longer appropriate and will be eliminated as of October 1, 2001.
1.1.3.5 Intrastate Backbone Transmission Rights for Core Market and Wholesale Customers’ Core Load:
1.1.3.5.1  SoCalGas retail core:  The initial reservation effective October 1, 2001 of firm backbone transmission rights for use by SoCalGas’ Gas Acquisition Department to serve core customers procuring gas from SoCalGas is established by this Settlement Agreement as a total of 1000 MMcfd, consisting of 300 MMcfd at North Needles, 290 MMcfd at Topock, 340 MMcfd at Blythe, and 70 MMcfd on North Coastal.  This reservation is based on an assumption that SoCalGas will be providing procurement service for 90% or more of core throughput.  This reservation must be accepted in full for the year beginning October 1, 2001.  Each subsequent year, SoCalGas’ Gas Acquisition Department has the option to reduce its reservation based on the amount by which its market share of core procurement service has declined below 90% of total core throughput.  For example, if the percentage of core procurement service it is then providing has declined to 80% prior to October 1, 2002, SoCalGas’ Gas Acquisition Department may reduce its reservation by any amount up to 11.1% (i.e., 10/90) effective October 1, 2002.  The way in which SoCalGas’ Gas Acquisition Department implements such a reduction as between receipt points will be addressed in an implementation filing for this Settlement Agreement and be subject to Commission approval.  SoCalGas agrees that its Gas Acquisition Department will meet and confer with the Office of Ratepayer Advocates prior to exercising any option to reduce its reservation on October 1, 2002 and each year thereafter during the term of this Settlement Agreement.  SoCalGas’ Gas Acquisition Department may not obtain capacity in the open seasons for backbone transmission rights in any year of this Settlement Agreement, but may obtain additional backbone transmission rights in the secondary market or individually-negotiated backbone capacity contracts after the open season.  SoCalGas’ Gas Acquisition Department may also sell any backbone transmission rights it holds in the secondary market in any amount, at any receipt points, and for any remaining portion of the term of the Settlement Agreement.  SoCalGas’ Gas Acquisition Department shall have the option to take its reserved backbone transmission capacity either at the 100% reservation charge rate design at $.07191 cents per dth (subject to annual escalation as described in this Settlement Agreement) or at a rate design that has 50% of the total rate in a reservation charge and 50% volumetric charge based on a total rate of $.07591 cents per the (subject to annual escalation).  SoCalGas Gas Acquisition may elect any combination of the two rate designs for stated capacity at any receipt point (e.g., it could have half of its capacity at Topock at 100% reservation charge, the other half at Topock at 50/50, all of its Blythe capacity at 50/50 and all of its North Needles capacity at 100% reservation charge).
1.1.3.5.2  CTAs on the SoCalGas system:  Each CTA will have the option prior to the commencement of the open season on October 1, 2001, and each year thereafter for the term of this Settlement Agreement, to reserve firm backbone transmission rights for a term of one year at each of North Needles, Topock and Blythe equal to the then-existing interstate capacity rights reserved for SoCalGas’ Gas Acquisition Department as specified in Section 5.3 below, times the share of the total core market served by that CTA.
1.1.3.5.3   SDG&E:  Because SDG&E’s Wheeler Ridge Access Agreement is suspended during the term of this Settlement Agreement as provided in Section 1.1.3.6.6, SDG&E through its Core Gas Supply Department will be assigned backbone transmission rights prior to the initial open season as described in this section in order to match SDG&E’s existing upstream transportation commitments, some of which extend beyond the term of the Settlement Agreement.  SDG&E shall have a firm backbone reservation of 50 MMcf/day at Wheeler Ridge and 10 MMcf/day at Blythe.  SDG&E’s Core Gas Supply shall have the option to take this reserved backbone transmission capacity either at the 100% reservation charge rate design at $.07191 per dth (subject to annual escalation as described in this Settlement Agreement) or at a rate design that has a 50% reservation charge and a 50% volumetric charge based on a total rate of $.07591 per dth (subject to annual escalation).  SDG&E’s Core Gas Supply Department can select any combination of the two rate designs for either of the receipt points (e.g., at Wheeler Ridge it could elect 100% reservation for 30 MMcfd and 50/50 for 20 MMcfd, and all 50/50 at Blythe) subject to this process.  SDG&E’s Core Gas Supply Department may participate in the open seasons, and may acquire or sell backbone transmission rights in the secondary market in the same manner as described above for SoCalGas’ Gas Acquisition Department.
1.1.3.5.4  Other wholesale customers:  Each wholesale customer other than SDG&E will have the following two options prior to the commencement of the open season on October 1, 2001, and each year thereafter in the term of this Settlement Agreement.  Only one option may be selected at a time.  If one is selected, it must be selected for all eligible volumes, not just a portion.  Neither option has to be selected.
1.1.3.5.4.1	Option 1:  To reserve backbone transmission rights for a term of one year at each of the SoCalGas receipt points to match the customer’s contractual commitments upstream of each receipt point.  Only upstream commitments in existence as of April 17, 2000, and with a remaining term on April 17, 2000, of at least 5 years will qualify for this treatment.  Also, the quantities will be limited to the core requirements of California customers of the wholesale customer (if the contractual commitments for upstream capacity exceed the wholesale customers’ core requirements, the customer’s matching rights will be pro rated to the customer’s upstream commitments upstream of each receipt point); or
1.1.3.5.4.2	Option 2:  To reserve backbone transmission rights for a term of one year at each of North Needles, Topock and Blythe equal to the then-existing interstate capacity rights reserved for SoCalGas’ Gas Acquisition Department as specified in Section 5.3 below, times the ratio of the wholesale customer’s core throughput as a percentage of the total SoCalGas core market.  The options described above for CTAs and other wholesale customers if exercised must be exercised in full and not in part
1.1.3.5.3	If CTAs and other wholesale customers exercise the options stated above, they shall have the choice of taking the reserved backbone transmission capacity either at a rate design with a 100% reservation charge at $.07191 per dth (subject to annual escalation as described in this Settlement Agreement) or at a rate design with a 50% reservation charge and a 50% volumetric charge at a total rate of $.07591 per dth (subject to annual escalation).  CTAs and other wholesale customers can mix the rate designs (for specified amounts of capacity) at the same receipt point and between receipt points.  CTAs and all wholesale customers may participate in the open seasons, and may acquire or sell backbone transmission rights in the secondary market without restriction.

1.1.3.6	Open Season Process:  Firm backbone transmission rights not awarded to SoCalGas’ Gas Acquisition Department, CTAs, or wholesale customers by the terms of Section 1.1.3.5 above shall be made available through an open season.  The first open season shall be conducted shortly before October 1, 2001, and the results thereof shall be effective on that date.  Details of the process consistent with the terms of this Settlement Agreement, including the exact timing of the open season prior to the October 1 effective date, shall be resolved in an implementation process subject to final approval by the Commission.  Special rights for existing on-system California gas producers to obtain backbone transmission rights for Line 85 and North Coastal receipt points are described in Appendix B.  The capacity remaining for these points after California producer and core reservations are available in the open season, subject to the 50% limitation for each such point’s remaining capacity in stage one and two of the initial open season as described below.
1.1.3.6.1:  First stage of initial open season:  Only existing noncore (including wholesale customers) to the extent of their historical load and CTAs to the extent of their currently-contracted-for load are entitled to participate in the first stage.  Customers entitled to participate in the first and second stages may assign their rights to participate to a third party (such as a marketer).  Customers entitled to participate may submits bids in the first stage for an amount of backbone rights up to 100% of their historical consumption, and may bid to acquire such rights at any receipt points or combination of receipt points.  The maximum customers can bid in the first and second stages will be based on their consumption in the most recent annual period for which data is available prior to conduct of the open season.  Customers’ maximum bidding rights shall be determined by a formula that fairly balances seasonal and annual usage.  SoCalGas will also offer seasonal capacity in the open season.  The rate for seasonal capacity will be based on 120% of $.07191 per dth, with a 100% reservation charge rate design; a 50/50 rate design will not be offered for seasonal capacity.  No more than 50% of the capacity remaining after the SoCalGas Gas Acquisition Department capacity reservation at any individual receipt point will be subject to being contracted in the first stage or second stage of the open season.  
1.1.3.6.2  Second stage of initial open season:  Customers who were eligible for the first stage may participate in a second stage to bid for any capacity not contracted for in the first stage and under 50% of the capacity remaining at an individual receipt point after the SoCalGas Gas Acquisition Department capacity reservation.
1.1.3.6.3  Third stage of initial open season:  The third stage of the initial open season is open to any creditworthy person.  The capacity available in the third stage is all firm capacity not awarded through reservations or the first two stages.  A minimum of 20% of the capacity at each receipt point remaining available for the third stage shall be offered for a term of one year only.  The remaining capacity shall be offered for up to the full remaining term of this Settlement Agreement. 
1.1.3.6.4  Open Seasons after the Initial Open Season:  SoCalGas shall conduct open seasons annually.  Open seasons after the initial open season shall have one stage only and shall not provide any preferential rights as in the first two stages of the initial open season for existing end-use customers to acquire backbone transmission capacity.  For the open seasons after the initial open season, SoCalGas shall offer all firm capacity that was not contracted for in the prior open seasons and capacity under contracts that expire at or during the period for which the current open season is being held.  In open seasons after the initial open season, SoCalGas must offer on a one-year basis as much capacity as it offered on a one-year basis in the third stage of the initial open season.
1.1.3.6.5  Prices that can be bid and value of bids:  In all stages of each open season, bidders must bid either a 100% reservation charge rate design at a postage stamp rate of $.07191 per dth (plus escalation as described in this Settlement Agreement) or a 50% reservation charge/50% volumetric charge  rate design at $.07591 per dth (plus escalation), except for special provisions applicable to capacity offered on a seasonal basis.  Bidders must state the rate designs they are bidding for specific amounts of capacity by receipt point and by term, but may make multiple bids for specified capacity at a particular receipt point, each with different rate designs, and may bid different rate designs for different receipt points.  Bids may be for any term up to the full remaining term of this Settlement Agreement, except that for capacity offered for a maximum of one year, the maximum term that can be bid is one year.  Bids at the two rate designs will be treated equally for purposes of awarding capacity.  Only the term bid will be used to determine which bids are awarded in which volume, if more volume is bid than is available for a particular receipt point in a particular stage (including the 50% limitations in the first two stages, and separately for the 20% one-year capacity and for the other term capacity in the third stage).  Capacity will be awarded to those bidders who bid for the longest term if more volume is bid than is available for a particular receipt point.  In stages one and two, bids for capacity for a term of a year or more will be given priority over bids for seasonal capacity in the award of capacity rights for over-subscribed receipt points.  If more volume is bid for at the same term than is available for a particular receipt point, all such bidders will be awarded capacity on a basis pro rata to the amounts they bid at that term for that point.  All bids once submitted cannot be withdrawn.  Successful bidders are contractually liable for all capacity awarded to them in the open season process.
1.1.3.6.6	Wheeler Ridge Access Agreements:  This Settlement Agreement provides that SoCalGas’ Wheeler Ridge Access Agreement with Southern California Edison Company shall be cancelled as of the effectiveness of firm intrastate backbone transmission rights on October 1, 2001, and that Edison shall owe no amounts for service under its Access Agreement for service provided after that date.  This Settlement Agreement provides that SDG&E’s Wheeler Ridge Access Agreement shall be suspended as of the effectiveness of firm intrastate backbone transmission rights on October 1, 2001, and until August 31, 2006.  SDG&E shall have no obligations or rights for service under its Access agreement for the this period of suspension.  SDG&E shall owe no amounts under its Access Agreement with respect to service during that period of suspension of its Access Agreement.
1.1.3.7	Sale of Capacity Not Awarded in Open Season:  SoCalGas may sell backbone transmission capacity not awarded in the open season to any person on an individually-negotiated basis, subject to the limitations described in this section.  This capacity may include sale on a firm basis of firm capacity as quantified in this Settlement Agreement at any receipt point not subscribed in the open season.  The negotiated rates for such firm capacity may include a rate design including reservation charges, up to a rate design with 100% of the rate in a reservation charge.  SoCalGas may also sell under negotiated contracts on an interruptible basis capacity that may be available from time to time above the firm capacities as quantified in this Settlement Agreement.  The negotiated rates for such interruptible capacity shall be all-volumetric.  SoCalGas may negotiate any level of rate for such firm or interruptible capacity subject to a cap of 120% of the postage stamp rate of $.07191.  Firm capacity unsubscribed in the open season and sold by SoCalGas under negotiated contracts shall have the same firmness of service as other firm service.  Otherwise, SoCalGas shall not market firm or interruptible capacity in negotiated contracts in a manner that would degrade service to customers with firm service awarded in the open season.  SoCalGas shall not engage in undue discrimination or preference or in tying of backbone capacity to other service offerings, but it is not required to offer all parties the same terms in negotiation.  SoCalGas remains subject to Commission regulation of affiliate transactions. 

1.1.3.8  Treatment of Local Transmission Costs: On October 1, 2001, backbone transmission costs as quantified in this Settlement Agreement will be removed from bundled transportation rates, and SoCalGas shall be at risk for recovery of such backbone transmission costs through rates for unbundled backbone transmission service.  On October 1, 2001, local transmission costs as quantified by this Settlement Agreement shall be reallocated in bundled transportation rates as provided below in order to ensure that the effect of this Settlement Agreement, exclusive of the unbundling of SoCalGas core interstate pipeline capacity provided in Section 5.3, will have almost no impact on the allocation of costs between core and noncore customer classes.  Local transmission costs are quantified on an embedded cost basis at an agreed-upon level of $64.3 million for 2000.  (Local transmission cost of $64.3 million plus backbone cost of $73.7 provided in Section 1.1.3.2 equals total transmission cost of $138.0 million provided in Section 1.1.3.2.)  The amount of $64.3 million shall escalate on January 1, 2001 according to the annual indexing formula (inflation less productivity plus customer growth, with adjustment for any “Z factors”) adopted by the Commission for SoCalGas’ current base rate PBR in D.97-07-054.  Effective October 1, 2001, local transmission costs as quantified in this Settlement Agreement shall be allocated in rates between customer classes on the basis of cold year throughput.  Allocation of local transmission costs in bundled transportation costs between customer classes may be modified by the Commission after the term of the BCAP period adopted by the Commission in the decision to be issued in A.98-10-012.  In all Commission proceedings for the full term of this Settlement Agreement, the allocation of transmission costs between local and backbone, and of common costs (A&G and general plant) to the transmission function, shall be consistent with the manner in which transmission costs are quantified by this Settlement Agreement.  This Settlement Agreement allocates 7.5% of common costs to the transmission function.

Nothing in this Settlement Agreement shall have the effect of overriding, nullifying or dictating whether or not there shall be a “Sempra-wide” rate design for electric generation or any other class of customers for service at any time in the term of this Settlement Agreement, provided that SoCalGas backbone transmission and unbundled storage service shall be provided, including to SDG&E and its customers, as specified in this Settlement Agreement.

SoCalGas’ risk/reward for recovery of local transmission costs in bundled transportation rates from October 1, 2001, to the end of the BCAP period to be adopted in A.98-10-012 shall be the same as for the period before October 1, 2001, provided in the decision in A.98-10-012 (i.e., assuming no change from the Proposed Decision, there will be 100% balancing account treatment in the core market and 75/25 ratepayer/shareholder treatment in the noncore market for differences between actual and forecast throughput).  SoCalGas’ risk/reward for recovery of local transmission costs after the 1999 BCAP period is to be determined by the Commission in future proceedings, such as the BCAP following the 1999 BCAP.

1.1.3.9 Market Concentration Limitations:  No person shall be entitled to acquire through the initial open season process more than 40% of the capacity at any individual receipt point that has not been awarded to SoCalGas’ Gas Acquisition Department or CTAs or wholesale customers in the process described in section 1.1.3.5 above.  Capacity acquired in the open seasons after the initial open season, the secondary market, or through individually-negotiated contracts with SoCalGas is not subject to the 40% limitation.  For purposes of the 40% limitation, the holdings of any affiliate of the person shall be included.  "Affiliate" means any person, corporation, utility, partnership, or other entity 50 (fifty) per cent or more of whose outstanding securities are owned, controlled, or held with power to vote, directly or indirectly either by the person or any of its subsidiaries, or by that person’s subsidiaries. 
1.1.3.10      Potential for Bypass of Local Transmission and Distribution Systems:  This Settlement Agreement does not address the issue of whether customers can directly connect to SoCalGas’ backbone transmission system, and if they do so, whether they must pay any or all of SoCalGas’ charges other than charges for backbone transmission service.  These issues are left to the Commission to decide if and when it chooses to do so.  Nothing in this Settlement Agreement prevents any Party from seeking or opposing any resolution of these issues by the Commission.

1.2	Establish a Secondary Market for Intrastate Transmission Capacity
1.2.1	Summary of D.99-07-015:  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)

1.2.2	Current status:  No secondary market currently exists for intrastate transmission rights on SoCalGas or SDG&E because no such rights currently exist.

1.2.3	Resolution:  All backbone transmission rights on SoCalGas as defined in Section 1.1 are assignable to any creditworthy person, whether or not an end-user or wholesale customer on the SoCalGas system.  Rights may be re-assigned any number of times under the same rules applicable to assignments by persons who originally obtained the rights directly from SoCalGas.  Provisions for platforms for trading backbone transmission and storage rights are addressed in Section 6.3.

1.2.3.1	Assignability:  Assignments may consist of all or part of the backbone transmission customer’s contract quantity and all or part of the backbone transmission customer’s remaining contract term.  Contract assignments are subject to the following requirements:
i.	Assignors must notify SoCalGas in advance of their assignments.
ii.	The assignee must satisfy SoCalGas’ creditworthiness requirements described below in Section 1.2.3.2.  If  SoCalGas’ creditworthiness requirements are satisfied, SoCalGas shall so notify the assignor and the assignor will then be relieved of all liability for performance by the assignee for the remainder of the term of the contract.   Alternatively, the assignor may, at its option, waive the creditworthiness requirements applicable to the assignee, in which case the assignor shall be secondarily liable for non-performance by the assignee.  If an assignor exercises this option, it must demonstrate to SoCalGas’ satisfaction that it remains creditworthy itself.

1.2.3.2	Creditworthiness standards for assignment of backbone transmission rights: 
a.	An entity requesting service must demonstrate creditworthiness before receiving service.  Additionally, an entity receiving service under a long-term (one year or longer) contract may be subject to periodic re-evaluations of its creditworthiness.  An end-use customer existing as of October 31, 2001, who has already met existing creditworthiness standards in effect immediately prior to that date shall be deemed to be creditworthy with respect to receiving assignment of backbone transmission rights up to the amount necessary to meet its historical level of demand, but remains subject to periodic re-evaluations of its creditworthiness if receiving service under a contract of one year or longer in term.
b.	An entity requesting service must provide the following to SoCalGas in order for SoCalGas to evaluate its creditworthiness;
		i.   Most recent annual report;
		ii.  Most recent SEC Form 10-K;
iii. If SEC Form 10-K is unavailable, substitute annual financial statements audited by a Certified Public Accountant for the three most recent years (including a balance sheet, income statement, and cash flow statement), or
iv.   Most recent quarterly or monthly financial statements (including a balance sheet, income statement, cash flow statement, and contingencies) accompanied by an attestation by the providing entity’s Chief Financial Officer that the information reflected in the financial statements is true and correct and a fair representation of the entity’s financial condition.
v.  Any other financial information as may be required by SoCalGas to access credit risk including but not limited to an organizational structure statement indicating relationships between the ultimate parent, corporate affiliates, subsidiaries, limited liability companies and limited partnerships.

c. 	SoCalGas will use the information above, in conjunction with the entity’s service request or service level, to determine the entity’s maximum credit line, either secured or unsecured. 
d. 	A creditworthiness evaluation may be conducted by an outside credit analysis agency, to be determined by SoCalGas, with final credit approval granted by SoCalGas.  Credit reports will remain strictly confidential between the credit analysis agency and SoCalGas.
e. 	If an entity is unable to demonstrate creditworthiness through the materials listed in Section b, the entity may still obtain credit approval if it elects to provide security which is acceptable to SoCalGas.
f. 	The entity may submit an alternate form of security acceptable to SoCalGas in lieu of the creditworthiness evaluation.  Alternate forms of security must be submitted to SoCalGas Gas before the entity’s contract is executed.
g. 	To assure the continued validity of an established secured or unsecured credit limit, the entity shall be required to furnish SoCalGas Gas with financial information satisfactory to SoCalGas Gas, annually or as requested by SoCalGas, during the entity’s term of service.  In the event SoCalGas determines that a financial change has or could adversely affect the creditworthiness of the entity, security may be requested by SoCalGas.  If the entity does not provide the requested financial information or any additional security requested , SoCalGas may terminate service. 
h. 	Acceptable forms of security deposits are:
i. 	an irrevocable and renewable standby letter of credit, issued by a major U.S. financial institution acceptable to SoCalGas and in form, substance and amount satisfactory to SoCalGas;
ii. 	cash deposit which will earn interest at the interest rate on Commercial Paper(prime, three-month), as described in Preliminary Statement, Part I, Section J;
iii. 	a renewable surety bond in a form acceptable to SoCalGas and issued by a major insurance company acceptable to SoCalGas.
iv. 	a guarantee, in form and substance satisfactory to SoCalGas, executed by a guarantor deemed creditworthy by SoCalGas.  At the sole discretion of SoCalGas, guarantees may be required to be accompanied by other forms of security deposit in an amount determined appropriate by SoCalGas.
v. 	such other form of security as the entity may agree to provide and as may be acceptable to SoCalGas.

j)	The entity may provide other forms of collateral to reduce the required security, if agreed to by SoCalGas at its sole discretion and in a form acceptable to SoCalGas.
k)	SoCalGas will treat all financial statements provided to it as confidential.  
l)	Establishment of creditworthiness for the Core Aggregation Transportation and Contracted Marketer Transportation programs are covered in Rules 32 ad 35, respectively.

1.3	Place the Utility At Risk for Unused [Transmission] Resources
1.3.1	Summary of D.99-07-015:  The Commission refers to the fact that SoCalGas’ shareholders are partially at risk for “stranded” costs associated with intrastate transmission.  (p. 12)
1.3.2	Current status:  The Global Settlement put SoCalGas shareholders at 100% risk for any deviation between forecast and actual throughput from the noncore (excluding EOR) market as applied to all-volumetric transportation rates that include the cost of the transmission system.  The PD in the 1999 BCAP recommends adoption of 75/25% ratepayer/shareholder risk for any difference between forecast and actual noncore throughput.
1.3.3	Resolution:  For the period from the effective date of this Settlement Agreement until the implementation of a system of firm, tradable intrastate backbone transmission rights pursuant to this Settlement Agreement on October 1, 2001, SoCalGas shareholder risk for recovery of the costs of its intrastate transmission system shall be subject to the terms of the Commission’s decisions in the SoCalGas PBR adopted in D.97-07-054 and the Commission’s decision to be issued in SoCalGas’ 1999 BCAP A.98-10-012.  Effective October 1, 2001, SoCalGas shall be 100% at shareholder risk/reward for recovery of unbundled backbone transmission costs as quantified by this Settlement Agreement through the rates charged for such service.  Any amount by which revenues for backbone transmission service differ from unbundled costs established by the Settlement Agreement shall not be subject during the term of this Settlement Agreement to the earnings sharing mechanism under SoCalGas’ current PBR adopted in D.97-07-054 or any successor earnings sharing mechanism that may be adopted.  Effective October 1, 2001, SoCalGas’ risk for recovery of local transmission and distribution costs (i.e., other than for unbundled backbone transmission and storage) shall be as established by the Commission in its decisions in SoCalGas’ current PBR and 1999 BCAP for the effective period adopted therein (i.e., through December 31, 2002 per the PD in the 1999 BCAP), and in successors to those two proceedings for the period thereafter.

1.4	Establish Hector Road as a Delivery Point on the SoCalGas System	

1.4.1    Summary of D.99-07-015:  The Commission sees reason to pursue a change in SoCalGas’ nomination procedures even in the short term to establish Hector Road as a formal receipt point for which customers can nominate on the SoCalGas system.  It finds that failure to provide at least “window-style” access through Hector Road has resulted in lost opportunities to bring relatively inexpensive gas into southern California.  It seeks specific proposal on how such an arrangement should be defined, including burdens that would fall on Transwestern Pipeline customers.  The Commission also states that it is unlikely the market will accurately reflect the value of intrastate transmission unless Hector Road is a formal receipt point in a SoCalGas firm, intrastate transmission rights system.  It expects that Hector Road would be a formal receipt point in any such system.  (pp.15-19; FoF 3 and 4.)

1.4.2   Current Status:  SoCalGas has a physical interconnection with Mojave Pipeline at Hector Road.  SoCalGas currently receives gas at that point from Mojave Pipeline on a discretionary basis for purposes of operational efficiency, but customers are not allowed to make nominations for transportation from Hector Road as a formal receipt point on the SoCalGas system.

1.4.3   Resolution:  Hector Road will be established as a formal receipt point on the SoCalGas system at which volumes can be nominated.

1.4.3.1	For the period from the effective date of this Settlement Agreement through September 30, 2001, the following provisions shall apply:  The Hector Road interconnection will be established by SoCalGas as a formal receipt point on the SoCalGas system at which volumes can be nominated by transportation customers on the SoCalGas system.  The total capacity available to be nominated at Hector Road will be subject to adjustment daily based on operating conditions, but such capacity will be at least 50 MMcfd as long as Mojave Pipeline delivers at least 50 MMcfd at Hector Road on each day for which volumes equal to or greater than 50 MMcfd are nominated for delivery at Hector Road.  Volumes nominated at Hector Road in excess of 50 MMcfd would be secondary to nominations on SoCalGas’ system for deliveries from Transwestern Pipeline Company (“Transwestern”) at SoCalGas’ North Needles receipt point.  SoCalGas will not set the maximum daily receipt point capacity at North Needles at less than 750 MMcfd unless operating conditions unrelated to the Hector Road receipt point require such action.  All volumes delivered at Hector Road will be subject to the Wheeler Ridge access fees and surcharges as long as the Commission keeps any such fees or surcharges in effect with respect to deliveries at Wheeler Ridge.  This Settlement does not prohibit the Commission from eliminating the Wheeler Ridge access fee and from rolling-in Wheeler Ridge interconnection costs.
1.4.3.2	Upon the implementation of a system of firm, intrastate backbone transmission rights on the SoCalGas system provided under this Settlement Agreement for October 1, 2001, Hector Road shall be a formal receipt point on the SoCalGas system with a firm receipt point capacity of 50 MMcfd.  Details regarding the Hector Road receipt point under the system of firm, tradable intrastate backbone rights are provided in Section 1.1 of this Settlement Agreement.
1.4.3.3	Establishment of Hector Road as a formal receipt point for nominations into the SoCalGas system (whether prior to or upon the implementation of a firm intrastate capacity system for SoCalGas) is conditioned on the existence of Hector Road as a formal delivery point by Mojave Pipeline under its tariffs approved by the Federal Energy Regulatory Commission (“FERC”).  The Parties agree not to oppose having Hector Road as a formal delivery point for Mojave Pipeline.
1.5	Publish SoCalGas Windowing Criteria in Tariffs.  [Includes Implementing Targeted Operational Flow Orders]

1.5.1	Summary of D.99-07-015:  SoCalGas was directed to file an advice letter to publish its existing “windowing” procedures as part of its tariff.  It was not clear to the Commission what stakeholders might say about such procedures when they were filed, nor how long such procedures might remain in effect prior to the implementation of a system of firm intrastate transmission rights.  In the context of reviewing the advice letter and related pleadings, the Commission would determine whether to approve the procedures without comment or to require modifications. (pp.19-20, CoL 3., O.P. 8 and 12, Appendix C)  The Commission also 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], FoF 23, CoL 9, Appendix C))
1.5.2	Current Status:  SoCalGas filed its current windowing procedure in tariff form by Advice Letter 2837.  No action has been taken by the Commission on this filing.  SoCalGas continues to follow the procedure set forth therein.
1.5.3    Resolution:  The current “windowing” process on the SoCalGas system will be eliminated on the effective date of this Settlement Agreement.
1.5.3.1	Period until October 1, 2001:  For the period from the effective date of this Settlement Agreement to September 30, 2001, the system replacing SoCalGas’ current windowing system is as follows:  SoCalGas will adopt a system under which it will establish receipt point capacities, subject to revision daily, on the basis of physical maximums for each receipt point under the operating conditions expected for that day.  If SoCalGas customers’ nominations in total for a receipt point exceed SoCalGas’ physical maximum capacity for the day at that receipt point, SoCalGas will continue to have the upstream pipeline at the interconnection point determine which shippers’ gas will be scheduled up to the physical maximum based on the upstream pipeline’s capacity rights system.  The daily maximums for each receipt point will be posted on SoCalGas’ publicly available GasSelect system daily prior to the nomination deadlines.  
At the Wheeler Ridge receipt point there is more than one upstream pipeline/supply source.  Therefore, it is not possible to rely on a single upstream pipeline’s capacity rights system to allocate capacity at SoCalGas’ Wheeler Ridge receipt point when SoCalGas’ customer nominations exceed the physical maximum of that receipt point.  This Settlement Agreement allocates the Wheeler Ridge maximum daily physical capacity (including at least 50 MMcfd at Hector Road) between upstream delivery sources pro rata on the basis of the prior day's scheduled deliveries from each upstream source.  An example is shown below, assuming that the maximum daily physical capacity on a particular day has been established to be 830 MMcfd, and that total nominations for the Wheeler Ridge receipt point exceed 830 MMcfd:
		Wheeler Ridge Operating Capacity = 830 MMcfd

 Prior Day Sched. Del.			Allocated Capacity
Kern/Mojave	= 	300				           =     356 MMcfd 
PG&E	= 	325			                 =     385 MMcfd
Elk Hills	=  	  75			                 =       89 MMcfd
(Via Wheeler)	= 	700			                 =     830 MMcfd

Customer scheduled deliveries for each of the sources that deliver gas to SoCalGas at Wheeler Ridge would be reduced to the Allocated Capacity for each upstream source, as illustrated above, by the capacity rights system on the individual upstream sources.  For example, if 400 MMcfd had been nominated on PG&E, SoCalGas would inform PG&E it would accept only 385 MMcfd from PG&E, and PG&E would determine which customers’ gas would be delivered to total 385 MMcfd.
Effective with the implementation of firm intrastate backbone transmission rights on October 1, 2001, all of the preceding provisions of this Section 1.5.3.1 will be superseded by the system of firm intrastate backbone transmission rights provided in Section 1.1.

1.5.4	Operational Flow Orders:  This Settlement Agreement provides for the establishment of OFO procedures that are substantially consistent between SoCalGas and PG&E.  Existing provisions of SoCalGas Rule 30 regarding overnomination events and winter balancing rules will remain in effect until March 31, 2001.  Effective April 1, 2001, these existing provisions will be eliminated and the following provisions substantially consistent with those approved for the PG&E system will become effective for the SoCalGas system.

OFO procedures:  On a daily basis an assessment will be made to determine deliveries into the system are greater or less than expected usage plus assigned storage assets.  If deliveries are outside acceptable limits an OFO may be called.  OFO events will be determined for the Core customer class and the Noncore customer class independently.  Noncore OFO days will be declared when forecast deliveries are greater than or less than noncore demand plus default balancing assets (assigned storage balancing assets).  Core OFO events will be declared when forecast deliveries are greater or less than Core demand plus assigned storage assets.

During OFO events an imbalance charge will apply if, after chip trading, an imbalance outside of the tolerance exists. A Stage I OFO will have a $1/dth charge for being outside tolerance after chip trading.  During a Stage  II OFO the imbalance charge after chip trading will increase to $25/dth.  During the summer and winter operating seasons, Stage I OFOs will be declared early in the day prior to flow and Stage II OFOs will be declared prior to Cycle 2 if the Stage I OFO did not correct the imbalance for the system in total.  During the winter operating season, Stage II OFOs may be declared to protect system integrity even if a Stage I OFO had not been previously declared

Noncore customers who have the default balancing service (i.e., not those who have elected the self-balancing option) will have a tolerance band of ±10% during an OFO event.  The storage allocation for Core customers includes capacities for balancing purposes, and therefore no such tolerance band applies to Core during an OFO event.

On OFO days, if both Core and Noncore customer class OFOs have been declared, both classes will be allowed to chip trade with each other.  If only one customer has an OFO day then only those customers in that class may chip trade.

When operational conditions exist such that supply is insufficient to meet demand and delivery to end-users is threatened, the diversion of supply may be used to ensure continued gas delivery to core end-users.  OFO provisions will also apply under these conditions.  If a noncore end-user’s supply is diverted to prevent a curtailment of core customers, then that end-user must curtail its use of natural gas.  Similar to the PG&E system, there will be an additional $25/dth diversion charge assessed to any customer receiving involuntarily diverted gas supply.  The revenues from the diversion charge will be credited to the customers who had their gas diverted.  The institution of this involuntary supply diversion charge eliminates the need for SoCalGas' existing Service Interruption Credit.

Tariff language consistent with this aspect of this Settlement will be submitted for approval by the Commission in time to become effective on April 1, 2001.
Parties wish to ensure that there are not an excessive number of OFOs on SoCalGas’ system as a result of other changes provided for in this Settlement.  This Settlement in Appendix __ provides a process for triggering and conducting an “OFO Forum” if the number of OFOs or emergency OFOs called by SoCalGas under this Settlement exceeds eight (8) during the first two months of OFO-system implementation.  Among the measures the Commission may take on recommendation of the OFO Forum is the institution of “targeted” OFOs.
1.5.5	Gas Supply Pools on the SoCalGas System:  Parties to this Settlement have expressed interest in measures that would increase the liquidity of trading of gas supply in California and that would assist marketers and gas consumers in managing their gas supplies. One tool for this purpose that many interstate pipelines offer is pooling of shipper supplies.  This Settlement provides for the establishment by SoCalGas of pooling of gas supplies by customers and marketers on its system.

Pursuant to this Settlement Agreement, customers and marketers (including marketers without a specific end-use customer) will be permitted, but not required, to have pools on the SoCalGas system.  Customers and marketers will be permitted to trade gas among pools on a daily or nomination cycle basis without changing their nominations for deliveries from interstate pipelines.  SoCalGas will permit nominations from a receipt point to a pool, from storage to a pool, from one pool to another pool, and from a pool to storage or to customer burn.  Customers and marketers will not be permitted to hold imbalances in pools.  Thus, gas scheduled into a pool during any nomination cycle must be simultaneously scheduled out of a pool to burn, storage, or another pool.  California producers will be permitted to operate under their producer balancing agreements for gas produced in California.  Interstate pipeline nominations would be permitted to roll cycle-to-cycle and day-to-day until changed by the customer or marketer.  Additional details regarding the pooling system adopted by this Settlement are described in Appendix E.

SoCalGas may charge a fee for pooling transactions only to the extent set forth in Appendix E.  It is understood and agreed that the pool transfer fee described in Appendix E shall terminate on December 31, 2002, unless by that date SoCalGas has requested and the Commission has approved a continuation of that fee or some alternative.

Effective with implementation of firm intrastate backbone transmission rights on the SoCalGas system on October 1, 2001, pooling arrangements will be modified to add pools “at the city gate”.

California gas producers will have the option to operate under their existing producer balancing agreements for California-produced gas if they choose not to participate in the pooling arrangements described above.

2.	   STORAGE
2.1	Create Firm, Tradable Storage Rights
2.1.1	Summary of D.99-07-015:  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, FoF 9, CoL 4, Appendix C)

2.1.2   Current Status:  SoCalGas currently offers unbundled storage service with its storage capacity in excess of that amount of capacity reserved for the core market.  Pursuant to the decision in SoCalGas’ 1996 BCAP, D.97-04-082, the current storage reservations for SoCalGas’ core market are 70 Bcf of inventory, 327 MMcf/d of injection, and 1,935 MMcf/d of withdrawal capacity.  The PD and all alternates in the pending 1999 BCAP retain the same core reservations.  SoCalGas currently has 100% balancing account coverage, except for post-1992 expansion facilities, through the Noncore Storage Balancing Account pursuant to the Global Settlement, but this treatment is subject to revision in the 1999 BCAP.  The PD and all alternates in the 1999 BCAP provide for SoCalGas to be at risk for recovery of 50% of a specified level of unbundled storage costs.  Storage costs are currently allocated and unbundled on the basis of LRMC, and no change in that approach is provided in the 1999 BCAP PD or any alternates.
	SDG&E owns no storage facilities and no storage facilities are located on its gas system.  SDG&E currently contracts for storage service with SoCalGas to meet only the needs of its bundled gas sales customers and offers its noncore customers a pricing option under which they can control their own storage.  SDG&E has no risk for recovery of any of its storage costs except for that small segment whose costs are allocated to noncore utility procurement customers.

2.1.3	Resolution:  The amount of SoCalGas’ storage capacity made available to the unbundled market will be increased.  Unbundled storage will be unbundled on an embedded cost basis rather than an LRMC basis.  Unbundled storage capacity will be awarded in the form of firm, tradable rights, as described in Section 2.2 below.  Unbundled storage will be made available in the first instance through an annual open season process at embedded cost.  Uncontracted-for unbundled capacity can be marketed by SoCalGas on a negotiated contract basis, subject to ceiling and floor rates.  SoCalGas will be placed at 100% shareholder risk for unbundled storage after a two-year transition period with partial and increasing shareholder risk, as described in Section 2.3 below.
Under this Settlement Agreement, SDG&E will contract for storage only for its core procurement customers using the options for wholesale customers of SoCalGas (including to meet wholesale core load) provided in this Settlement Agreement.  All SDG&E transportation-only customers, including CTAs, will obtain any unbundled storage service they desire directly from SoCalGas pursuant to the options provided by this Settlement Agreement.
2.1.3.1 Quantities of Storage Capacity Unbundled:  SoCalGas’ total storage capacity, exclusive of Montebello, consists on a firm basis of 105.6 Bcf inventory, a minimum of 803 MMcfd of injection, and a minimum of 3,125 MMcfd of withdrawal.  Firm injection and withdrawal have minimums because the amount of injection and withdrawal vary with the amount of gas in inventory. The injection and withdrawal rates per mcfd established in section 2.1.3.2 represent annualized costs for those capacities.  The injection figure, when multiplied by 803 MMcfd of minimum firm summer injection capacity expected to be adopted in the 1999 BCAP produces the total fixed embedded cost of injection in the year 2000.  Firm injection rights are subject to modest prorationing in the winter, however, because of compressor maintenance that is necessary during that period.  The withdrawal figure, when multiplied by the 3,125 MMcfd of official withdrawal capacity per the expected 1999 BCAP, produces the total fixed embedded cost of withdrawal in the year 2000.  This firm withdrawal figure is based on an assumed inventory level of 25 Bcf.  In recognition of the fact that actual withdrawal capabilities are strongly affected by inventory in storage (i.e., "drive gas"), Parties will develop a method by which all customer's firm withdrawal rights on any given day is a function of their individual inventories.  This will facilitate the trading of firm withdrawal rights in secondary markets, and it will relieve the core of its current responsibility to maintain drive gas (peak day minimums) to support noncore storage commitments.  Like injection rights, withdrawal rights are subject to modest prorationing in the summer due to maintenance work on dehydration/withdrawal facilities that is necessary during the summer.

Effective April 1, 2001, this Settlement Agreement revises the total core storage reservation (including for balancing purposes) to be 55 Bcf of inventory capacity, 327 MMcfd of injection, and 1,935 MMcfd of withdrawal capacity.  Storage assets allocated to default noncore balancing service are established as 5.3 Bcf, 250 MMcfd of injection, and 250 MMcfd of withdrawal, subject to reductions for self-balancing elections.  SoCalGas’ storage capacity above the total core storage reservation, plus any portion of the total core storage reservation that is not accepted by the core pursuant to the terms of Section 5.4 of this Settlement Agreement and any portion of default noncore balancing that is released by virtue of election of self-balancing service, shall be made available for unbundled storage service pursuant to the terms described in this Section below.

2.1.3.2 Allocation of costs of storage capacity and rates for unbundled storage:  This Settlement Agreement establishes the total annual revenue requirement on an embedded cost basis for total SoCalGas storage capacity, excluding Montebello, at $71.6 million for calendar year 2000, plus $.028 per dth ($3.3 million) of variable costs, plus 2.44% in-kind fuel costs for injection/withdrawal.  This Settlement Agreement establishes the total annual revenue requirement on an embedded cost basis for the total core reservation of storage at $34.15 million, which includes a credit of $1.25 million for miscellaneous oil revenues as described further below, plus $.028 per dth variable costs and 2.44% in-kind fuel costs.  The embedded cost of storage assets as stated in the section above for default balancing service before self-balancing elections is $12.87 million in annual revenue requirement.  The embedded cost per unit of inventory, injection, and capacity are as follows:  $0.20548 per year per dth of inventory capacity rights, $39.000 per year per dth/day of injection capacity rights, and $5.585 per year per dth/day of withdrawal rights.  Annual charges are to be paid in 12 monthly installments.  The dollar figures above for annual revenue requirement; inventory, injection, and withdrawal cost per unit; variable costs; and oil revenues shall escalate on January 1, 2001 and 2002 according to the annual indexing formula (inflation less productivity plus customer growth, with adjustment for any “Z factors”) adopted by the Commission for SoCalGas’ current base rate PBR in D.97-07-054.  Effective January 1, 2003, and thereafter for the term of this Settlement Agreement, they will escalate by whatever Commission-adopted PBR or attrition formula generally applicable to SoCalGas’ base rates is in effect at the time.  All storage rates calculated herein assume a Btu content per mcf of 1,016.  The Btu conversion factor may be modified with Commission approval for good cause during the term of the Settlement Agreement, and any rates based thereon would be adjusted accordingly.  The estimate of oil revenues associated with the operation of storage fields, exclusive of Montebello, of approximately $2.5 million currently reflected as a credit to rates through miscellaneous revenues shall be removed from bundled core and noncore rates.  Instead, a percentage of $2.5 million in oil revenue equal to the ratio of the core’s embedded cost of storage to the total embedded cost of storage ($1.25 million based on the total core reservation described in Section 2.1.3.1) shall be used to reduce the embedded cost of storage reserved for core customers.  Any remaining oil revenues received by SoCalGas shall be treated the same as revenues for unbundled storage services under this Settlement Agreement.  In all Commission proceedings for the full term of this Settlement Agreement the allocation of common costs (A&G and common plant) to the storage function shall be consistent with the manner in which storage costs are quantified by this Settlement Agreement.  The calculation of the cost of storage in this Settlement Agreement includes the allocation of 3.6% of common costs (A&G and common plant) to storage.  
2.1.3.3 Effect of unbundling of storage costs on other rates:  Effective April 1, 2001, SoCalGas’ cost of storage shall be allocated and unbundled on the embedded cost basis that is quantified by this Settlement Agreement.  Noncore bundled transportation rates will reflect only the cost of balancing service consistent with the terms of Section 3.2 of this Settlement Agreement.  The cost of capacity reserved for the core market and not rejected to the extent permitted under Section 5.4 will be allocated solely to core customers.  Remaining storage costs, including the amount of storage rejected by core customers and storage not used for balancing due to customer elections for self-balancing service, will be recovered by SoCalGas solely through charges for unbundled storage service described in this Section; subject, however, to recovery in bundled transportation rates of any amounts that are subject to balancing account (or partial balancing account) protection through March 31, 2003.
2.1.3.4 Open Seasons:  SoCalGas shall conduct an open season for unbundled storage service shortly before April 1, 2001, for service effective that date, and annually thereafter for the term of this Settlement Agreement.  Details of the process consistent with the terms of this Settlement Agreement, including the exact timing of the open season prior to the April 1 effective date, shall be resolved in an implementation process subject to final approval by the Commission.  SoCalGas shall offer in the initial open season all storage capacity not committed to core, wholesale core, and balancing service.  Twenty (20%) of the capacity available in the initial open season shall be offered for a term of one year.  The remaining 80% shall be offered for a term of up to the full remaining term of this Settlement Agreement.  All capacity offered in the initial and following open seasons shall be offered and awarded as a linked package of inventory, injection, and withdrawal capacity in the ratio of 1 Bcf of inventory/7.6 MMcfd of injection/29.6 MMcfd of withdrawal.  Bidders in the open season can bid for any amount of inventory, injection, and withdrawal capacity, but the ratio must be the same as stated in the preceding sentence (e.g., a bidder may bid for a package including 0.5 Bcf, 3.8 MMcfd of injection, and 14.8 MMcfd of withdrawal).  Because the total amount of capacity by product available in the open season may not have the same ratios as the ratio specified above, the requirement for bids in this ratio may result in capacity in two of the three storage products not being awarded in the open season.  Such capacity would then become available to the market through Schedule G-TBS as described below.  The rate for the package of products for which bids can be made in the open season is fixed at $0.667 per year per dth (equivalent to $0.678 per year per mcf with a 1,016 Btu/mcf conversion factor) of inventory capacity reserved in a package for all inventory, injection, and withdrawal capacity included in any package in the specified ratios.  This rate is to be adjusted annually per PBR as described above.  This rate is to be paid as a fixed reservation charge without regard to actual usage of the capacity reserved, and billed in 12 monthly installments.  In-kind fuel and variable rates would continue to be charged for actual usage in addition to this rate.  All bids for capacity offered for a one-year term must be for that full year at the full rate.  If bids for one-year capacity exceed the amount of such capacity offered, the capacity will be awarded pro-rata to the volumes bid.  All bids for capacity not limited to a one-year term must be made at the full rate, but may specify any term not to exceed the full remaining term of the Settlement Agreement.  If more bids are submitted for capacity not limited to one year terms than the amount of such capacity available, the available capacity will be awarded to bidders with the longest terms whose bids taken together equal the capacity available.  If the volume of bids for the same term plus all longer bids are greater than available capacity, then all the longer bids will be awarded in full and all remaining capacity will be awarded to the bidders at the same term pro rata to their bids for that term.  Any capacity not awarded in an open season and not otherwise committed to core markets, wholesale core requirements, or balancing service, may be marketed by SoCalGas through G-TBS or G-BSS storage tariff schedules as described in the following section.  In open seasons subsequent to the initial open season, SoCalGas will offer the same quantity of capacity for a one-year term that it offered in the initial open season.  Any capacity available at the time of a subsequent open season beyond the amount offered for a one year term in the initial open season will be marketed through Schedule G-TBS, not another open season.
2.1.3.5	Pricing flexibility for unbundled storage capacity not committed during open seasons:  Unbundled storage capacity not committed during open seasons may be sold by SoCalGas under the terms of Schedules G-TBS and G-BSS existing as of the filing of this Settlement Agreement, subject to price floors and ceilings described below.  For the period from the effective date of this Settlement Agreement to March 31, 2001, SoCalGas’ pricing flexibility for unbundled storage service under Schedule G-TBS shall be as provided in applicable Commission decisions and resolutions prior to the date of this Settlement Agreement and the 1999 BCAP decision when issued.  For the period any contract is in effect from April 1, 2001, to March 31, 2002, for each storage product (injection, inventory, withdrawal) the floor price that SoCalGas may charge on Schedule G-TBS is 50% of the embedded cost of that product as established by this Settlement Agreement and the maximum price that SoCalGas may charge for each product is 150% of the embedded cost of that product as established by this Settlement Agreement.  For the period any contract is in effect from April 1, 2002, to March 31, 2003, for each storage product (injection, inventory, withdrawal) the floor price that SoCalGas may charge on Schedule G-TBS is 50% of the embedded cost of that product as established by this Settlement Agreement and the maximum price that SoCalGas may charge for each product is 200% of the embedded cost of that product as established by this Settlement Agreement.  For any period a contract is in effect from April 1, 2003, through the remainder of the term of this Settlement Agreement, for each storage product the floor price that SoCalGas may charge on Schedule G-TBS is the short-run marginal cost of providing that product, and there is no ceiling price.  SoCalGas may sell any mix of storage products to a customer in the unbundled storage market under Schedule G-TBS at any time in the term of this Settlement Agreement.

If SoCalGas divests ownership to an unaffiliated person or persons of 20% or more of its existing storage inventory capacity (plus a reasonably proportionate amount of injection and withdrawal capacity) prior to April 1, 2003, it shall immediately be entitled to the pricing flexibility under Schedule G-TBS described above otherwise applicable on and after April 1, 2003.  The 20% shall be measured as a percentage of SoCalGas’ storage inventory capacity exclusive of the Montebello storage field (i.e., 20% of approximately 105.6 Bcf) and divestiture of Montebello shall not count toward the 20%.  Only forms of divestiture that give the purchaser the option to continue to use the capacity to provide storage services will count toward the 20%.  This Settlement Agreement does not create any obligation for SoCalGas to divest storage capacity other than the Montebello field, nor does it obligate the Commission to approve any such divestiture.

The G-BSS storage tariff shall remain in effect for the term of this Settlement Agreement, but shall be closed to new customers as the effective date of this Settlement Agreement.  Customers with G-BSS contracts in effect as of the effective date of this Settlement Agreement shall have the option through the remainder of the term of this Settlement Agreement to renew those contracts when they expire (or re-expire after any number of renewals), subject to the escalation of the G-BSS rates by the PBR escalation provisions.
2.1.3.6 Treatment of Storage Contracts Pre-existing April 1, 2001:  All storage contracts lawfully entered into on or before March 31, 2001, shall remain in effect for their full terms without modification by this Settlement Agreement.
2.1.3.7	Montebello Storage Field:  SoCalGas agrees that it will file with the Commission on or before June 1, 2000, a new application for authorization to sell its Montebello storage field.  The provisions of this Settlement Agreement do not include the Montebello storage field in the quantified capacities or costs of storage allocated to default balancing, core service, or the unbundled storage market (i.e., the revenue requirement associated with the Montebello field is bundled in base margin, subject to further Commission action on the matter).  This Settlement Agreement does not address whether sale of the Montebello field should be approved by the Commission, nor any ratemaking treatment of the Montebello field.  These issues are left to other Commission proceedings specifically addressing SoCalGas’ Montebello storage field.

2.2	Establish a Secondary Market For Intrastate Storage Capacity
2.2.1	Summary of D.99-07-015:  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)

2.2.2	Current Status:  Customers with unbundled storage service contracts on SoCalGas’ system currently can sell gas in storage to other customers with storage contracts, and can assign their storage contracts to other persons for the full remaining term of the contracts, subject to SoCalGas approval of the creditworthiness of the assignee.  Storage customers cannot assign their contracts for only part of their term and cannot assign only portions of the injection, inventory, and withdrawal rights they have under their contracts.  SoCalGas currently provides a space on its GasSelect bulletin board on which GasSelect customers can advertise interest in assigning or acquiring the assignment of storage contracts.

2.2.3	Resolution:  From the effective date of this Settlement Agreement through March 31, 2001, SoCalGas unbundled storage customers will be allowed to assign their full contract capacities (but not portions thereof) for periods of time less than the full remaining term of the contract, as well as for the full remaining term of the contract.

Effective April 1, 2001, through the remainder of the term of this Settlement Agreement, storage customers will be allowed to assign to any person, whether or not an end-user or wholesale customer of SoCalGas, any portions of their storage contract (inventory, injection, and withdrawal rights may be assigned independently) for any period up to the remaining term of their contracts.  Storage contract rights may be re-assigned any number of times under the same rules applicable to assignments by persons who originally obtained the rights directly from SoCalGas.  Details of the right to assign or trade storage rights are provided below.  Provisions for platforms for trading backbone transmission and storage rights are addressed in Section 6.3.

2.2.3.1	Assignability:  Assignments may consist of all or part of the storage customer’s contract quantities and all or part of the storage customer’s remaining contract term. Contract assignments are subject to the following requirements:
i.	Assignors must notify SoCalGas in advance of their assignments.
ii.	The assignee must satisfy SoCalGas’ creditworthiness requirements described below in Section 2.2.3.2.  If  SoCalGas’ creditworthiness requirements are satisfied, SoCalGas shall so notify the assignor and the assignor will then be relieved of all liability for performance by the assignee for the remainder of the term of the contract.  Alternatively, the assignor may, at its option, waive the creditworthiness requirements applicable to the assignee, in which case the assignor shall be secondarily liable for non-performance by the assignee.  If an assignor exercises this option, it must demonstrate to SoCalGas’ satisfaction that it remains creditworthy itself.

2.2.3.2	Creditworthiness standards for assignment of storage rights: 
a.	An entity requesting service must demonstrate creditworthiness before receiving service.  Additionally, an entity receiving service under a long-term (one year or longer) contract may be subject to periodic re-evaluations of its creditworthiness.  
b.  An entity requesting service must provide the following to SoCalGas in order for SoCalGas to evaluate its creditworthiness;
		i.   Most recent annual report;
		ii.  Most recent SEC Form 10-K;
iii. If SEC Form 10-K is unavailable, substitute annual financial statements audited by a Certified Public Accountant for the three most recent years (including a balance sheet, income statement, and cash flow statement), or
iv.   Most recent quarterly or monthly financial statements (including a balance sheet, income statement, cash flow statement, and contingencies) accompanied by an attestation by the providing entity’s Chief Financial Officer that the information reflected in the financial statements is true and correct and a fair representation of the entity’s financial condition.
	v.  Any other financial information as may be required by SoCalGas to access credit risk including but not limited to an organizational structure statement indicating relationships between the ultimate parent, corporate affiliates, subsidiaries, limited liability companies and limited partnerships.

c.   SoCalGas will use the information above, in conjunction with the entity’s service request or service level, to determine the entity’s maximum credit line, either secured or unsecured. 
d.   A creditworthiness evaluation may be conducted by an outside credit analysis agency, to be determined by SoCalGas, with final credit approval granted by SoCalGas.  Credit reports will remain strictly confidential between the credit analysis agency and SoCalGas.
e.   If an entity is unable to demonstrate creditworthiness through the materials listed in Section b, the entity may still obtain credit approval if it elects to provide security which is acceptable to SoCalGas.
f.   The entity may submit an alternate form of security acceptable to SoCalGas in lieu of the creditworthiness evaluation.  Alternate forms of security must be submitted to SoCalGas Gas before the entity’s contract is executed.
g.   To assure the continued validity of an established secured or unsecured credit limit, the entity shall be required to furnish SoCalGas Gas with financial information satisfactory to SoCalGas Gas, annually or as requested by SoCalGas, during the entity’s term of service.  In the event SoCalGas determines that a financial change has or could adversely affect the creditworthiness of the entity, security may be requested by SoCalGas.  If the entity does not provide the requested financial information or any additional security requested , SoCalGas may terminate service. 
h.   Acceptable forms of security deposits are:
i.	an irrevocable and renewable standby letter of credit, issued by a major U.S. financial institution acceptable to SoCalGas and in form, substance and amount satisfactory to SoCalGas;
ii.cash deposit which will earn interest at the interest rate on Commercial Paper(prime, three-month), as described in Preliminary Statement, Part I, Section J;
iii.	a renewable surety bond in a form acceptable to SoCalGas and issued by a major insurance company acceptable to SoCalGas.
iv.	a guarantee, in form and substance satisfactory to SoCalGas, executed by a guarantor deemed creditworthy by SoCalGas.  At the sole discretion of SoCalGas, guarantees may be required to be accompanied by other forms of security deposit in an amount determined appropriate by SoCalGas.
v.	such other form of security as the entity may agree to provide and as may be acceptable to SoCalGas.
i.	The entity may provide other forms of collateral to reduce the required security, if agreed to by SoCalGas at its sole discretion and in a form acceptable to SoCalGas.
j.	SoCalGas will treat all financial statements provided to it as confidential.
k.	Establishment of creditworthiness for the Core Aggregation Transportation and Contracted Marketer Transportation programs are covered in Rules 32 and 35, respectively.

2.3	Place the Utility At-Risk for Unused [Storage] Resources
2.3.1	Summary of D.99-07-015:  The Commission requests the parties to consider the costs and benefits related to creating a system of tradable storage rights on SoCalGas’ system that places the utility at risk for unused resources.  (pp. 20-24, Appendix C)
2.3.2	Current Status:  The Global Settlement provided for shareholder recovery of all SoCalGas’ unbundled storage costs, except for post-1992 “expansion” facilities, through the Noncore Storage Balancing Account, with the balance in the account spread over customers on an equal cents per therm basis.  The Global Settlement guaranteed this treatment through August 31, 1999.  The PD in the pending SoCalGas 1999 BCAP recommends the adoption of a 50/50 risk sharing in lieu of the Global Settlement’s provisions, subject to modification in I.99-07-003.  SDG&E does not own any underground gas storage facilities.
 
2.3.3	Resolution:  
For the period from the effective date of this Settlement Agreement to March 31, 2001, SoCalGas’ risk/reward for unbundled storage costs shall be as determined by the Commission in SoCalGas’ 1999 BCAP A.98-10-012.
Assuming the Joint Recommendation in the 1999 BCAP is adopted, there is a sum related to previous undercollections in the NSBA that are to be amortized over the BCAP period.  This Settlement Agreement provides for the recovery of any of this amount not amortized by the date of approval (not the effective date) of this Settlement Agreement as follows:  The remaining amount would be amortized over the period from the approval of this Settlement Agreement to March 31, 2001.  Any residual balance left in the account as of March 31, 2001 would be transferred to the fixed cost accounts for core and non-core (CFCA & NFCA) to complete the revenue recovery.

For the period from April 1, 2001, through March 31, 2002, SoCalGas shall be at risk/reward for 50% of any difference (whether negative or positive) between unbundled storage costs and revenues from unbundled storage service.  The remaining 50% of any difference shall be allocated to ratepayers on an equal cents per therm basis between core and noncore customer classes, and recovered as part of bundled volumetric rates for transportation service.
For the period from April 1, 2002, to March 31, 2003, SoCalGas shall be at risk/reward for 75% of any difference (whether negative or positive) between unbundled storage costs and revenues from unbundled storage service.  The remaining 25% of any difference shall be allocated to ratepayers on an equal cents per therm basis between core and noncore customer classes, and recovered as part of bundled volumetric rates for transportation service.
For the period from April 1, 2003, through the remainder of the term of this Settlement Agreement, SoCalGas shall be 100% at risk/reward for any difference between unbundled storage costs and revenues from unbundled storage service.

3.	BALANCING

3.1	Examine Structural Means For SoCalGas To Provide Balancing Services Without Drawing On Core Assets.

3.1.1	Summary of D.99-07-015:  The Commission stated that as long as core services are intertwined with system balancing, it is unlikely the Commission can ensure the process is free of cross-subsidies or incentives for SoCalGas to favor its shareholders.  The Commission stated it was not prepared to institute mandatory daily balancing as a means of avoiding use of core assets to balance the system.  (pp.36-38; 49; 62; FoF 17, 19-21; CoL 7)

3.1.2	Current status:  SoCalGas currently has only monthly balancing tolerances, except for winter balancing rules and overnomination events.  Winter balancing rules limit customers to specified tolerances over a five-day period if storage inventories are above a specified level and to daily balancing tolerances if storage is below specified levels.  On days other than overnomination events, there are no limits on how much customers may be overdelivered.  When overnomination events are called, they apply to all market segments.
As a wholesale customer of SoCalGas, SDG&E is balanced on the SoCalGas system in the aggregate.  SDG&E’s transportation-only customers are subject to SDG&E tariff provisions that mirror current SoCalGas balancing tolerances.  When SoCalGas overnomination events are called or winter balancing rules apply, SDG&E transportation-only customers are required to balance to the same limits SoCalGas imposes on its transportation customers.

3.1.3	Settlement provisions:  This Settlement Agreement provides for the noncore (including wholesale) and core (including both retail core and CAT core) classes to be balanced separately on the SoCalGas system, effective April 1, 2001.  Storage assets used for balancing are identified separately for noncore and core classes and their costs allocated separately for noncore and core balancing service.  SoCalGas’ core gas procurement department will be expressly subject to the same rules and penalties as other core balancing entities.  SoCalGas Gas Operations department may buy or sell gas in emergency circumstances to balance the system, but SoCalGas’ core gas procurement department will play no role in such purchases.  SoCalGas Merger Conditions 16 and 17 (Appendix B to D.98-03-073) are deemed satisfied so that no temporarily confidential communications SoCalGas’ Gas Operations and Gas Procurement Department will be allowed any longer pursuant to Merger Condition 16 after March 31, 2001.
As described in Section 3.2 below, noncore customers will have the option of choosing the default balancing service offered by SoCalGas or electing a daily self-balancing option.  For noncore balancing, SoCalGas storage assets of 250 MMcfd of storage injection 250 MMcfd of storage withdrawal and 5.3 Bcf of inventory capacity will be assigned to manage customer imbalances.  Core customers will balance solely utilizing storage assets assigned to the core.  OFOs (Stage I and II) will replace all existing SoCalGas tariff Rule 30 overnomination event and winter balancing rules effective April 1, 2001.  OFO days will be determined independently for Core and Noncore customer classes, utilizing the assigned storage assets of each customer class.  Monthly balancing and imbalance trading with cash-out provisions will remain in place.  For OFO chip trading beginning April 1, 2001 will be offered.  Monthly cumulative imbalance trading is offered to all balancing entities regardless of customer class or balancing election.

Default noncore balancing entities are limited to a monthly imbalance of 10%.  After the end of the month, the imbalances can be traded with all balancing entities.  Following trading, any imbalance that remains outside the tolerance level will be subject to a cash-out at 50% (buy-back) or 150% (sell) of the average Southern California Border price per NGI’s Daily Gas Price Index during the imbalance period.

Default Core Procurement Group and CAT balancing entities are limited to a monthly imbalance of 0%.  However, their imbalance is calculated as the difference between supply deliveries and forecast (Attachment F) (provided 24 hours prior to each flow day) and they can fully utilize their assigned or acquired storage assets to manage their imbalances.  Following the imbalance trading period, any imbalances that remain, will be subject to a cash-out at 50% (buy-back) or 150% (sell) of the average Southern California Border price per NGI’s Daily Gas Price Index during the imbalance period.

This Settlement Agreement does not change the principles for balancing currently in effect that SDG&E applies to its system and customers.
3.2	Cost and Rate Separation for Balancing Services [Self-Balancing Option]
3.2.1	Summary of D.99-07-015:  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)

3.2.2	Existing Provisions:  
3.2.2.1	Currently, SoCalGas and SDG&E provide noncore transportation customers with a specific amount of balancing bundled in transportation service and rates 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.  SoCalGas and SDG&E’s pipeline operations must also manage other imbalances including shrinkage, pipeline-to-pipeline imbalances, California gas production imbalances and/or imbalances due to forecast error for core loads on the day of gas flow.  
3.2.2.2	The resources used by SoCalGas pipeline operations for balancing include the gas in the pipelines (called pipeline inventory or linepack) and the firm storage assets on the SoCalGas system.  There is no underground storage on the SDG&E system.  If injection requests exceed system capacity, overnomination events are called by SoCalGas which impose daily balancing limits and penalties for that day.  In addition, SoCalGas imposes additional limitations on imbalances during winter periods, in which limitations increase in two steps if system storage inventory levels fall below pre-established levels.  Finally, SoCalGas imposes daily “windowing” restrictions on the amount of gas that can be nominated by shippers in total for receipt at individual receipt points into the SoCalGas system.
3.2.2.3	Balancing entities are limited to a monthly imbalance of ±10 percent.  After the end of the month, they can trade imbalances outside this range.  Following trading, amounts outside ±10 percent are cashed-out.  There are no specific daily balancing limits, except on overnomination or undernomination event days and except for winter balancing rules.

3.2.3	Self-Balancing Option Provisions: As part of this Settlement Agreement, SoCalGas will offer an unbundled daily balancing option, which is called the Self-Balancing option, effective April 1, 2001.  This option allows customers to receive a credit for a portion of the balancing costs that will otherwise be bundled in the transportation rate recovering local transmission and distribution costs.
This Settlement Agreement does not provide for SDG&E to offer a self-balancing option to its customers and does not allow shippers on the SDG&E system (including SDG&E for its own core procurement customers) to elect self-balancing on the SoCalGas system.
The following provisions will apply to SoCalGas Self-Balancing:
3.2.3.1	Default Balancing:  The current 10% monthly balancing tolerance provided by SoCalGas will remain the default monthly balancing service for noncore customers who do not elect the Self-Balancing option.  The intent of the Parties is that the offering by SoCalGas and the election by customers of the Self-Balancing option will not adversely affect the availability, reliability or cost of default balancing, nor will it cause the frequency of OFOs to be any greater than would be the case in the absence of this option.  As provided in Section 3.2.3.7, the OFO Forum will monitor these effects, and meet to discuss and resolve concerns if such adverse effects occur.
3.2.3.2	Availability and Election of Self-Balancing Option:  The Self-Balancing option is available to noncore customers, wholesale customers, and CTAs.  For CTAs, a daily forecast of demand will continue to be used to measure daily imbalances, similar to how OFOs are done.  SoCalGas’ Gas Acquisition Department agrees that for the term of this Settlement Agreement it will not elect the Self-Balancing option.
3.2.3.3	Transmission Rates:  All of the costs agreed to be included in rates for noncore default balancing will be included in the bundled transportation rate for local transmission and distribution, not the unbundled backbone transmission rate or any rate for unbundled storage service. 
3.2.3.4	Allocation of Balancing Storage Assets:  Assets for default noncore (including wholesale) balancing, prior to any customer elections for Self-Balancing Service are 5.3 Bcf of inventory capacity, 250 MMcfd of injection capacity, and 250 MMcfd of withdrawal capacity.  To the extent that noncore customers elect Self-Balancing, a pro rata share of this capacity will be transferred to the unbundled storage program.  The amount is calculated as a pro rata share of the default balancing storage assets based on the customers’ annual average usage as a percentage of SoCalGas’ average annual system usage.  This amount of the balancing storage assets will be assigned to and remarketed through SoCalGas’ at-risk unbundled storage program.  If a customer elects to return to default balancing from Self-Balancing during the annual election period, then the same amount of storage is reassigned back to default balancing.  Balancing assets for the core market as a whole are included in the allocation of reliability/balancing storage to the core described in Section 5.4.4.
3.2.3.5	Limitations on Self-Balancing Option:  There are no limitations on how many noncore (including wholesale) customers or CTAs may elect the Self-Balancing Option, or on the amount of load that may be subject to the Self-Balancing Option.
3.2.3.6	Credit for Self-Balancing:  Those customers and CTAs electing Self-Balancing will receive a credit equal to $0.0159 per decatherm times their actual monthly metered usage (or that of their customers in the case of CTAs).
3.2.3.7	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, including impacts that may arise due to CTAs electing Self-Balancing.  After reviewing the data, the OFO Forum may recommend revising the Self-Balancing option and/or pipeline operating parameters. 
3.2.4	Self-Balancing Option Terms and Conditions:  Customers electing the Self-Balancing option will be subject to the following terms and conditions.
3.2.4.1	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 default 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.
3.2.4.2	Customers will be responsible for tracking their own daily imbalance position.  SoCalGas will not be required to provide warnings or other notice that a customer is falling outside the prescribed Self-Balancing tolerances before imbalance charges are incurred.
3.2.4.3	CTAs electing the Self-Balancing option will have their daily imbalances calculated on an estimate of their customers’ daily gas usage.  For CTAs whose demand is smaller than five percent (5%) of the core market (based on annual demand), daily usage will be determined using the first 24-hour forecast available each day.  For CTAs whose demand is greater than or equal to five percent (5%) of the core market, daily usage will be determined using an end of the gas day forecast, reflecting actual weather conditions rather than forecast weather conditions.  For any CTA electing Self-Balancing, the applicable daily usage forecast will also be used to calculate its monthly cumulative imbalance available for trading or carry forward. 
3.2.4.4	Customers electing the Self-Balancing option will be subject to two imbalance limits each day.  
3.2.4.4.1     The daily imbalance cannot exceed plus or minus five percent (±5%) of that day’s metered or forecast usage.  This tolerance does not change on OFO days applicable to the Self-Balancing customer; and
3.2.4.4.2	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 usage of the customer in the same month of the prior year, but may be adjusted prior to the month in question to reflect forecast load growth or reduction from the prior year.  This tolerance does not change on OFO days applicable to the Self-Balancing customer.
3.2.4.5	SoCalGas will calculate the daily imbalances after the calendar month for each balancing entity electing this option after processing the applicable meter data.  Daily imbalances for CTAs will be based on their daily usage as described in Section 3.2.4.3 above.  
3.2.4.6	Noncompliance charges will be calculated for customers electing the Self-Balancing option as the sum of the following:
3.2.4.6.1	For each non-OFO day, a noncompliance charge equal to $1.00 per decatherm per day for each day when the daily imbalance exceeds ±5 percent of the daily metered or determined usage.  
3.2.4.6.2	For each OFO day, the rate for calculating a noncompliance charge shall use the greater of the rate of $1.00 per decatherm per day or the rate applicable for calculating OFO noncompliance charges.
3.2.4.6.3	For each day including OFO 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.
3.2.4.6.4	For each OFO day on which a Self-Balancing customer exceeds its daily imbalance limit in a direction opposite to that of the OFO situation, there will be no noncompliance charge under Section 3.2.4.6.3 above.  For example, under a high inventory OFO, a balancing entity with a negative daily imbalance exceeding -5% would not receive a noncompliance charge for this situation.
3.2.4.7	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 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 except on noncore OFO days as allowed for default balancing customers.  However, trading of OFO day imbalance rights (chips) will be allowed as provided in Section 3.3.3 below.
3.2.4.8	Following each annual election period, SoCalGas will report within 30 days on its GasSelect system 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.
3.3	Electronic Trading of Imbalances [Including Rights]
3.3.1	Summary of D.99-07-015:  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)

3.3.2	Anonymous Monthly Imbalance Trading
3.3.2.1	Current SoCalGas Platforms for Monthly Imbalance Trading:  SoCalGas currently provides a platform on GasSelect for customers to give notice of their interest in trading imbalances, but it has no features beyond allowing customers to post messages in that space on GasSelect.
3.3.2.2	Provider of Electronic Imbalance Trading System:  SoCalGas will contract with an affiliate of Altra Energy Technologies, Inc. (ALTRA®) to provide the monthly imbalance trading platform using their Altrade® product.  The sole source provision of this contract will be in effect through December 31, 2002.  Once SoCalGas finalizes a 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 qualified provider may provide service in competition with ALTRA.  At that time, SoCalGas will provide a customer service and data interface with all interested qualified providers offering electronic imbalance trading.
3.3.2.3	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.
3.3.2.3.1	SoCalGas will continue to provide its platform for entities to post and confirm monthly imbalance trades without charging transaction fees.
3.3.2.3.2	Use of the anonymous trading platform is voluntary. 
3.3.2.3.3	ALTRA is a logical sole-source provider.  ALTRA is well recognized as an industry leader in building and servicing electronic trading platforms.  ALTRA is accorded a similar sole-source provider role for the same time period under the PG&E settlement filed in I.99-07-003 on January 28, 2000, and pending Commission approval.
3.3.2.3.4	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 information available on the trading screens to do their own deals outside the trading platform.  These deals can then be reported through SoCalGas' existing platform, thus avoiding transaction fees.
3.3.2.3.5	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.
3.3.2.3.6	SoCalGas will be entitled to retain a share of ALTRA’s transaction fee to assist in offsetting SoCalGas' transaction and credit costs, as well as reflecting the value SoCalGas brings to this service, subject to the cap provided in Part I, Section 1.6.1.1 of this Settlement Agreement.  The fee sharing will also provide an incentive to SoCalGas to encourage use of this trading service.  The fee shall be established by ALTRA with any revenues shared between ALTRA and SoCalGas as mutually agreed between SoCalGas and ALTRA.
3.3.2.3.7	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.  
3.3.2.3.8	SoCalGas shall not influence, in any way, ALTRA’s selection of trading partners, business associations or contracts with any third party operating on the SoCalGas system, other than in matters of routine credit and nomination capacities envisioned by this Settlement Agreement.
3.3.2.4	System Features for Electronic Imbalance Trading System:  The following provisions will be part of the monthly imbalance trading system limitations and features.
3.3.2.4.1	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.
3.3.2.4.2	Anonymous trading on ALTRA platform will not be required to abide by all the imbalance trading limitations in SoCalGas’ tariffs during the trading period.  However, the final summation of the imbalance trades completed on ALTRA’s trading platform and those posted on SoCalGas’ platform will be subject to SoCalGas’ tariffed balancing limitations and cash-out provisions.  The limitations include:  no trading across months; and trades into or out of on-system storage accounts must have documented inventory gas or space available.
3.3.2.4.3	SoCalGas 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 SoCalGas.  SoCalGas will add additional trades that are confirmed through SoCalGas’ 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 SoCalGas’ tariffs. 
3.3.2.4.4	Entities will be subject to trading limitations based on individual credit limits and system operating limitations.  SoCalGas will revise its credit-worthiness requirements in its tariffs to reflect these transactions.  SoCalGas 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.
3.3.2.4.5	SoCalGas will accept the credit risk for entities which are SoCalGas customers approved for this program, including designated marketers 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, SoCalGas will guarantee payment to the Seller in the transaction.  SoCalGas will then take collection action against the Purchaser, including late fees and, if appropriate, cashouts in accordance with requirements of SoCalGas tariff provisions regarding balancing.
3.3.2.4.6	To encourage additional liquidity, ALTRA may allow market makers that have no imbalances on the SoCalGas system to participate in imbalance trading.  ALTRA will be responsible for credit approval and collection for these market makers, pursuant to its agreement with SoCalGas.  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. 

3.3.3	Trading OFO Day Imbalance Rights
3.3.3.1	Objectives:  SoCalGas 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.  OFOs will be called on the SoCalGas system independently for noncore and core markets.  OFO imbalance trading described below can occur only within class (core or noncore) for which an OFO has been called on a particular day, except that if an OFO is called on the same day for both core and noncore markets, daily imbalances can be traded between as well as within the two classes for that day.
3.3.3.2	Market Benefits:  A daily balancing tolerance level of ±10% for customers with default balancing service is specified for each day an OFO is called.  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 within the tolerance level to gain value from this position, while helping the balancing entities outside the tolerance band to reduce their noncompliance charges.  
3.3.3.3	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.
3.3.3.3.1	The imbalance rights or chips are calculated as the difference on that OFO day between the entities’ imbalance and the OFO tolerance level.  The imbalance is calculated as the difference between scheduled deliveries to burn (including firm injection and withdrawal) and usage.  Since the core’s balancing rights are implicit within their total reserved storage rights, for chip trading purposes the core’s OFO tolerance level will be the lesser of 10% of burn or any unused firm storage rights.  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.
3.3.3.3.2	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 different 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. 
3.3.3.3.3	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.  
3.3.3.3.4	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.
3.3.3.3.5	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.
3.3.3.4	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 SoCalGas will establish the necessary interfaces, and ALTRA will provide the necessary screens and trading platform.  SoCalGas will ensure its systems will verify compliance with the trading rules, record the trades, and adjust the payments of noncompliance charges accordingly.  
3.3.3.5	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.  SoCalGas may receive a share of these fees, subject to mutual agreement between SoCalGas and ALTRA.  SoCalGas will be entitled to retain its share of the fees, subject to the cap provided in Part I, Section 1.6.1.1 of this Settlement Agreement.

4.	HUB SERVICES

4.1		Separate Utility Hub Services from Procurement Functions
4.1.1   Summary of D.99-07-003:  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)

4.1.2   Current Status:  SoCalGas’ Gas Acquisition Department offers tariffed hub services.  It uses storage capacity allocated to the core market (and not re-allocated to CTAs) and imbalances within permitted tolerances to offer these services.  Its hub revenues are included in the calculation of the penalty/reward under the Gas Cost Incentive Mechanism “GCIM”.

4.1.3	Resolution:  SoCalGas’ Gas Acquisition Department will continue to be allowed to offer hub services.  It will be restricted to using storage capacity allocated to it and any other storage rights it may acquire in the secondary market.  It will be restricted to the use of only those storage capacities for all purposes, including balancing its own purchases and deliveries and its provision of hub services.  The cost of such capacity is allocated pursuant to this Settlement Agreement solely to core procurement customers and SoCalGas’ Gas Acquisition Department cannot offer hub services using capacity whose cost is allocated to other customers.  Therefore, revenues from hub services provided by the SoCalGas Gas Acquisition Department will not be allocated to any customer class other than core procurement customers during the term of this Settlement Agreement.  The revenues will remain included in the calculation of the GCIM penalty/reward mechanism, subject to modification of that mechanism during the term of this Settlement Agreement.
In addition, the provisions of this Settlement Agreement with respect to storage may leave SoCalGas with storage capacity that is not contracted for on a firm basis (through the open season process or negotiated storage contracts) or assigned to SoCalGas’ Gas Acquisition Department.  This Settlement Agreement provides that SoCalGas may offer hub services with this uncontracted-for and unassigned storage capacity through a “pipeline” department of SoCalGas (such as its Gas Operations Department) that is wholly separate from SoCalGas’ Gas Acquisition Department.  This “pipeline” hub service would be basically the same in concept as the PG&E “Market Center”.  SoCalGas’ “pipeline” hub shall use no assets held by the SoCalGas Gas Acquisition Department.  There shall be no communication of nonpublic information between the two SoCalGas departments operating the two SoCalGas hub services regarding their respective hub services.  If SoCalGas wishes to offer “pipeline” hub services, it shall file tariffs covering them with the Commission, and the Commission shall not withhold approval of such tariffs that are consistent with the terms of this Settlement Agreement.  The maximum rates for such hub services shall be consistent with the maximum rates for storage contracts provided in this Settlement Agreement.  The revenues from “pipeline” hub services shall be subject to the at-risk provisions of Section 2.3 of this Settlement Agreement.

5.	CORE PROCUREMENT

5.1	Re-examine Utility Role in Core Procurement Once a Specified Competitor Market Share Has Been Achieved

5.1.1	Summary of D.99-07-003:  The Commission recommends the re-examination of local distribution company core procurement and the default provider function if 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 service as an option for core customers.  (pp.50-59, Appendix C).
5.1.2	Current Status:  SoCalGas and SDG&E offer procurement service to all core customers and are the default option for core procurement service.  They each have a core procurement market share of over 95% by volume.  AB 1421 was enacted in 1999 after the issuance of D.99-07-015 and addresses the role of the local distribution utility in providing core procurement service.
5.1.3	Resolution: The parties shall, within three months after Commission approval of this Settlement Agreement, use their respective best efforts to negotiate and enter into a separate settlement agreement on the following two issues:
1.	The parties shall consider competitive alternatives for providing procurement service to customers who do not choose a competitive provider.  Such alternatives to be considered shall include, but not be limited to, physical separation of the procurement department; new practices regarding functional separation; outsourcing of all or part of the procurement function in a competitively neutral fashion through a competitive bid procedure which would not exclude participation by affiliates; and combining the SoCalGas and SDG&E procurement functions; and
2.	The parties shall specifically consider performance mechanisms to provide SoCalGas and SDG&E with financial incentives, including, but not limited to, new performance incentive mechanisms based on objective measures of how well the utilities provide service to competitive suppliers (ESPs/CTAs) and their effectiveness in implementing any changes proposed or adopted for energy commodity procurement services.

Any such settlement of the foregoing two issues shall consider the following:  economic value to core ratepayers and the utilities' shareholders from the current practices used to provide these services; consumer protection; and promotion of competition.  If the parties cannot reach agreement on both issues within such three-month period, SoCalGas and SDG&E shall, within six months after Commission approval of this Settlement, file an application with a proposal to address these issues.  Nothing in this Settlement Agreement commits any Party to support or not oppose any issue considered in this process, and nothing in this Settlement Agreement commits the Commission to approve any proposal made pursuant to this Section.

5.2	Eliminate Core Aggregation Transportation Thresholds after Adoption of Consumer Protection Measures

5.2.1	Summary of D.99-07-015:  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.   (pp. 59-61, FoF 30, Appendix C)
5.2.2.	Current Status:  Currently, there is a 250,000 therms/year minimum threshold size on any persons seeking to qualify as or remain a core aggregation transportation marketer on SoCalGas or SDG&E’s systems.  Also, there is10% cap on the percentage of total core market share by volume that can be served by core aggregation transportation marketers on the systems of SoCalGas and of SDG&E, but SoCalGas and SDG&E are obliged to file for Commission review of this cap if the actual market share reaches 8%.

5.2.3	Resolution: CAT Participation Threshold:  There will be a reduction in  the CAT program minimum size requirement from 250,000 to 120,000 therms per year in order to provide general statewide consistency, upon the effective date of this Settlement Agreement.
Market Threshold:  There will be no cap on core market share participating in the CAT program in order to provide general statewide consistency, upon the effective date of this Settlement Agreement.
	Neither the reduction in participation threshold nor the elimination of the cap on market share are contingent on the passage of any legislation regarding consumer protection.  This Settlement Agreement does not address the issue of consumer protection measures, except as provided in Section 7.2.4.
Consistency with Electricity:  This Settlement Agreement endorses the principle that the gas utilities move toward standards and requirements that generally mirror the electric utility Direct Access Service request standards and requirements. 

5.3	Unbundle Utility Interstate Capacity Costs for Core Customers

5.3.1	Summary of D.99-07-015:  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)
5.3.2	Current Status:  The cost of interstate pipeline capacity on El Paso and Transwestern held by SoCalGas to meet requirements of the total core class remains bundled in transportation rates.  The Commission in 1995 ordered SoCalGas to file an application by the end of 1997 to unbundle core interstate capacity by the end of 1998.  The Commission dismissed that application in late 1998 because of the intervening passage of SB 1602.  CTAs are currently entitled to assignment by SoCalGas at the full as-billed rate of a share of El Paso and Transwestern capacity held for the core market prorata to their core market share.  SoCalGas’ contract with Transwestern expires on October 31, 2005.  SoCalGas’ contract with El Paso expires on August 31, 2006.
5.3.3    Resolution:  SoCalGas will unbundle core interstate pipeline costs upon the effective date of this Settlement Agreement.  As of that date, CTAs will be responsible for arranging on their own for the delivery of gas supplies to the SoCalGas system, and will not receive a mandatory assignment of any interstate capacity from SoCalGas.  CAT customers’ transportation rates will no longer include the as-billed cost of interstate capacity held by SoCalGas for the core market.  The stranded costs associated with such unbundling will be recovered by SoCalGas as described below.
5.3.3.1The initial reservations of interstate capacity for the core market as a whole for the term of this Settlement Agreement are established as of the effective date of this Settlement Agreement as 300 MMcfd on Transwestern at North Needles, 300 MMcfd on El Paso at Topock, and 444 MMcfd on El Paso at Blythe (Ehrenburg).
5.3.3.2SoCalGas shall release in the secondary market an amount of core interstate capacity proportional to the percentage of core market demand served by CTAs.  This amount may be modified from month to month as the percentage of core market demand served by CTAs changes.  All capacity released as a result of core market share being served by CTAs shall first be capacity on El Paso at Blythe until all 444 MMcfd of capacity at Blythe has been released.  Any capacity released beyond 444 MMcfd shall be released equally between Transwestern at North Needles and El Paso at Topock.
5.3.3.3SoCalGas shall have discretion as to how to release capacity that is stranded as a result of core interstate capacity unbundling.  SoCalGas generally expects to release this capacity on a month-to-month basis, but may release capacity for a longer period if in SoCalGas’ judgment doing so would reduce the amount of stranded costs.  SoCalGas may receive a price for released capacity greater than the as-billed rate to the extent permitted by FERC Order 637 or any successor provisions of federal law or regulations.  No person shall be allowed to challenge in a proceeding before the California PUC the reasonableness of the total level of revenues received by SoCalGas in the settlement period from the release of interstate capacity as a result of core interstate capacity unbundling, except if SoCalGas violates any regulations of this Commission or the Federal Energy Regulatory Commission that are generally applicable to releases of capacity by holders of firm interstate pipeline capacity.  No portion of any difference between the revenues from releasing interstate capacity held for the core or in excess of core requirements and the as-billed cost of that capacity to SoCalGas shall be allocated to SoCalGas shareholders for the term of this Settlement Agreement.
5.3.3.4	The stranded costs arising from the unbundling of core interstate pipeline capacity will be quantified as follows:  a) the volume of core capacity released on El Paso at Blythe times the difference between the El Paso as-billed rate and the average price received for core and noncore capacity released by SoCalGas on El Paso at Blythe; plus b) the volume of core capacity released on El Paso at Topock times the difference between the El Paso as-billed rate and the average price received for core and noncore capacity released by SoCalGas on El Paso at Topock; plus c) the volume of core capacity released on Transwestern times the difference between the Transwestern as-billed rate and the average price received for core and noncore capacity released by SoCalGas on Transwestern (i.e., the stranded cost per unit of released capacity at each receipt point will be the same for released core and released capacity in excess of total core requirements.)  All revenues from any release of capacity at a price above the as-billed rate will be credited first to reduce the stranded costs that would otherwise be borne by SoCalGas customers, and any excess would be used to reduce rates to SoCalGas customers.
5.3.3.5Allocation of stranded interstate capacity costs between core and noncore customer classes will be as follows:
For the period from the effective date of this Settlement Agreement through December 31, 2001:
There will be no change in the allocation between customer classes of stranded costs related to interstate capacity held in excess of the requirements of the core class as a whole (i.e., capacity held by SoCalGas on El Paso and Transwestern in excess of a total of 1044 MMcfd) from the allocation in place as of the time of the filing of this Settlement Agreement.
Stranded costs associated with the release of core interstate capacity will be allocated 50% to core customers in their transportation rate (i.e., to core utility procurement and CAT customers equally) and 50% to noncore customers; provided, however, that if the amount of stranded core interstate capacity costs that would otherwise be allocated to noncore customers under a 50/50 allocation exceed $2 million in calendar year 2000 or $5 million in calendar year 2001, the amounts above $2 million in 2000 and above $5 million in calendar year 2001 will be allocated to CAT customers only and not to noncore customers.  The $2 million and $5 million caps on allocation to the noncore market will not be pro rated for effectiveness of this Settlement Agreement for only a portion of a calendar year.
For the period from January 1, 2002, through the remainder of the term of this Settlement Agreement:
All stranded costs associated with interstate capacity in excess of the interstate capacity held for the core market will be allocated exclusively to the noncore market.  Core customers will no longer be allocated any share of the stranded costs of capacity in excess of that needed for the core market as a whole.
All stranded costs associated with interstate capacity held for the core market will be allocated exclusively to core customers.  Noncore customers will not be allocated any share of the stranded cost of capacity held for the core market.  Stranded costs associated with core interstate capacity will be allocated within the core market as follows:
Stranded costs associated with the release of the first 7% of interstate capacity held for the core market (i.e., 7% of 1044 MMcfd, or 73.08 MMcfd) will be allocated to all core customers on an equal cents per therm basis in the transportation rate (equally to core utility procurement and CAT customers).  Stranded costs associated with any amount of core interstate capacity released in excess of 7% of the total capacity held for the core market will be allocated between core residential and core non-residential customer classes in proportion to the percentage of total core CAT market share that has been elected by customers in each such core customer class.  For example, if 70% of all CAT volumes are in the core non-residential class, then 70% of the stranded costs associated with capacity released in excess of 7% will be allocated to the non-residential core class and the remaining 30% to the core residential class.  Within each core class, the stranded costs will be recovered in the transportation rate (equally to utility procurement customers and CAT customers).

5.3.3.6At least 20 days prior to the effective date of this Settlement, SoCalGas shall file an advice letter to adjust rates, consistent with this Settlement, to recover a forecast of the amount of stranded costs from core interstate capacity unbundling to be incurred in the calendar year in which this Settlement becomes effective.  SoCalGas shall adjust its rates effective on January 1 of each year thereafter to reflect a forecast of stranded costs for that calendar year.  Any difference between the amount of stranded costs forecast in setting rates and the recorded amount of stranded cost from core interstate capacity unbundling shall be tracked with interest at the short-term paper rate and subsequently recovered or refunded in rates.
5.3.3.7	As of the effective date of this Settlement Agreement, interstate pipeline capacity costs will be recovered from core customers taking procurement service from SoCalGas through monthly core procurement rates.  SoCalGas’ interstate capacity costs shall be an integral part of its procurement rate and need not be stated as a separate line item on bills from the rest of the procurement rate.  Inclusion of the interstate pipeline costs in SoCalGas’ procurement rate will not in and of itself have any impact on the operation of SoCalGas’ GCIM.

5.4	Unbundle Utility Storage Costs for Core Customers [Served by CTAs and Wholesale customers]
5.4.1	Summary of D.99-07-015:  The Commission recommends exploration of the unbundling of storage costs for core customers.  (p.49) 
5.4.2	Current CTA and Wholesale Storage Provisions:  Currently, each SoCalGas Core Aggregation Transportation marketer (CTA) is assigned a pro rata share of the total core allocated storage.  SoCalGas’ tariff schedules require that CTAs must fill and maintain their allocated storage inventory within specified limits to aid in customer cold weather system reliability.  Currently, wholesale customers are treated like all other noncore customers for purposes of access and use of SoCalGas storage.  Wholesale customers contract for storage from SoCalGas pursuant to unbundled storage service tariff schedules.  SDG&E owns no underground gas storage facilities.
5.4.3	Unbundling Storage Costs for CTAs and Wholesale customer core loads:  Parties agree to unbundle core storage costs for SoCalGas CTAs pursuant to the provisions below.  Parties also agree to special provisions for core loads of wholesale customers of SoCalGas as described below.
5.4.4	Provisions for CTAs on the SoCalGas system:  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.
Prior to any elections by CTAs provided by this Settlement Agreement with respect to storage capacity, the total amount of SoCalGas storage capacity reserved for the total SoCalGas core market (not including core requirements of SoCalGas wholesale customers) is as follows:
For reliability and balancing purposes:  35 Bcf of inventory, 234 MMcfd of injection, and 1935 MMcfd of withdrawal.
For all other purposes:  20 Bcf of inventory, 93 MMcfd of injection, 0 (zero) MMcfd of withdrawal.
5.4.4.1	Core Storage Rate Treatment:  As of the effective date of this Settlement Agreement, core storage costs will be recovered from core customers taking procurement service from SoCalGas through monthly core procurement rates and from CTAs through monthly fees to the extent they do not or cannot reject a reservation of core storage on behalf of their core transport customers.  SoCalGas storage cost may be an integral part of its procurement rate and need not be stated as a line item on bills separate from the rest of the procurement rate.  SoCalGas will not be at risk for the recovery of storage costs reserved for core customers taking procurement service from SoCalGas, except to the same extent as SoCalGas may possibly be put at risk, if at all, for local transmission and distribution costs of serving its core customers during the term of this Settlement Agreement.  The inclusion of storage costs in the SoCalGas procurement rate shall not in and of itself alter the SoCalGas GCIM.  The amount of storage reserved for SoCalGas core customers taking procurement service from SoCalGas will be the total core reserved quantities for reliability/balancing and non-reliability storage, less the amount reserved for CTAs prior to CTAs declining any amount of reserved reliability/balancing or non-reliability storage.
5.4.4.2	CTA Storage Reservations:  An allocation between SoCalGas’ utility core procurement customers and each CTA of the total core market reservations of storage inventory, injection, and withdrawal capacity for reliability/balancing purposes and for non-reliability purposes will be calculated each year in February based upon the ratio of total core market winter throughput and the volume of winter throughput of core customers who have contracted for procurement service from the CTA.
5.4.4.3	CTA Option to Accept or Reject Storage Reservation for Non-Reliability Purposes:  Each year between about February 15 and March 1, CTAs will be given the option to accept or reject all their annual reservation of storage for non-reliability purposes for the storage year of April 1 through March 31.  Rejections must be for the CTA’s full reservation, including all inventory and injection.  There is no limit on the amount of non-reliability storage reservation that can be rejected by CTAs as a group.  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. 
5.4.4.4	CTA Option to Accept or Reject Storage Reservation for Reliability/Balancing Purposes:  Each year between about February 15 and March 1, CTAs will be given the option to accept or reject any portion, up to 100%, of their Annual Reservation of storage for reliability/balancing purposes for the storage year of April 1 through March 31, subject to limitations on the rejection of reliability/balancing storage by the CAT market as a whole described below.  Rejections must include inventory, injection and withdrawal in the same proportion as the total core storage reservation for reliability/balancing purposes.  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.  CTAs electing not to reject their reliability/balancing storage reservation may still elect self-balancing service and receive the credit specified for this election.  The credit for CTAs electing self-balancing is specified in Section 3.2.3.6.
5.4.4.5	Cap on Rejected Reliability/Balancing Storage Allocations:  During the period from the effective date of this Settlement through March 31, 2003, the total amount of core storage allocations for reliability/balancing that can be rejected by all of the CTAs combined is capped for each storage season (April 1 to March 31) at 15% of the total core storage reservation for reliability/balancing; i.e., the cap is 5.25 Bcf of inventory capacity, 35.1 MMcfd of injection, and 290.25 MMcfd of withdrawal.  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.  This Settlement Agreement does not resolve whether there will be caps on rejection of reliability/balancing storage by CTAs for the period from April 1, 2003 through the termination of this Settlement Agreement.  This issue is left for the Commission to resolve prior to January 1, 2003.
5.4.4.6	Accepted and Assigned CTA Storage Allocations:  For amounts of reserved storage capacity (both reliability/balancing and non-reliability storage) that a CTA does not or cannot reject, the CTA will pay SoCalGas monthly, over the storage year, the revenue requirement associated with that capacity as specified by this Settlement Agreement.  CTAs must fill and maintain storage inventories on an annual cycle with respect to reserved reliability/balancing storage they do not or cannot reject as specified in the current SoCalGas tariff.
5.4.4.7	Disposition of Rejected Core Storage Allocations:  Core storage inventory allocations rejected by CTAs will be allocated to SoCalGas’ at-risk unbundled storage program.
5.4.4.8	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 customer requests for CAT service that have been processed to date, SoCalGas will recalculate the pro rata CTA reservations of reliability/balancing and non-reliability balancing storage, and compare this new calculation with the annual storage reservations calculated at the beginning of the current storage season.  If a CTA’s reserved share of storage inventory has increased by more than 100,000 therms, the CTA must choose whether to reject or accept an increased reservation for all or a portion of the incremental change.  This election must be made between August 15 and September 1.  
5.4.4.8.1	For amounts that the CTA accepts of these incremental storage rights, gas in the SoCalGas Gas Acquisition Department’s storage account will be transferred to the CTA account at a price that reflects a weighted average core procurement (per SoCalGas rate schedule) price for the months of April through October times an injection schedule for the SoCalGas Gas Acquisition Department.  The CTA will also pay the total cost of this storage capacity for that year in payments over the remainder of the storage year. 
5.4.4.8.2	For amounts that the CTA rejects of the reliability/balancing reservation, Alternate Resources, in like amount, will be required as described in Section 5.4.4.10 below.  Rejection of reserved reliability/balancing storage is subject to any cap for the current storage season.  To the extent rejected reliability/balancing storage capacity exceeds the cap during the intra-season election, the right to reject reliability/balancing storage will be pro rated among those rejecting storage capacity at this time.
5.4.4.9	Intra-Year Rules – Decrease In Load:  If the mid-year evaluation, described in Section 5.4.4.8 above, results in a decrease of more than 100,000 therms in the amount of storage inventory that would be reserved for a CTA and the CTA did not reject as of April 1 of that year at least as much storage reservation as the amount of its decrease, the CTA must transfer to the SoCalGas Gas Acquisition Department a share of its reduced reservation in a proportion equal to the percentage of its annual reservation that it did not reject for the year.  For instance, consider a CTA whose annual reservation was 400,000 therms, and which did not reject 300,000 therms, or three-quarters of its allocation.  If this CTA’s mid-year reservation was 250,000 therms, three-quarters, or 112,500 therms of the 150,000 therm reduced reservation would be transferred to the SoCalGas Gas Acquisition Department.  The gas in storage will also be transferred to SoCalGas Gas Acquisition Department, which will pay the CTA for the storage and gas on the same terms described in Section 5.4.4.8 above, to the extent that the total rejected capacity has been reduced.

5.4.4.10	CTA Certification of Alternate Resources:  A CTA rejecting all or part of a SoCalGas core storage allocation for reliability/balancing, must certify to SoCalGas 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 reliability/balancing 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 SoCalGas-allocated reliability/balancing storage that the CTA has rejected. 
5.4.4.10.1	Contracted firm storage services from SoCalGas or from an on-system CPUC-certificated independent storage provider;
5.4.4.10.2	Contracted firm SoCalGas 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
5.4.4.10.3	Third-party peaking supply arrangements, where that supply is backed up by contracts under Section 5.4.4.10.1 or 5.4.4.10.2 above.  
5.4.4.11	Release and Indemnification of SoCalGas:  Any CTA that elects to reject all or a portion of its core storage reservation for reliability/balancing shall enter into an agreement with SoCalGas releasing SoCalGas from any and all liability associated with that CTA’s rejection of its core reliability/balancing storage reservation.  In this agreement, the CTA shall be required to indemnify SoCalGas 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 SoCalGas-reserved reliability/balancing core storage had this storage not been rejected by the CTA.  

5.4.5	Provisions for SoCalGas Wholesale Customer Core Loads:  This Settlement Agreement does not alter any contracts for storage service between SoCalGas and any of its wholesale customers that are in effect at the time this Settlement Agreement becomes effective.  Upon the expiration of any such contract by a wholesale customer, and immediately upon the effectiveness of this Settlement Agreement for any wholesale customer who has no such contract, each wholesale customer may exercise an option to contract for a specific amount of storage capacity from SoCalGas for to meet reliability/balancing needs of its core load.  The storage capacity provided to a wholesale customer exercising this option would be taken from the storage capacity allocated to unbundled storage service, not from the reservation of storage for SoCalGas’ core market quantified in Section 5.4.4 above.  The amount of storage that the wholesale customer may elect to take is its last 12 months core throughput as a percentage of SoCalGas’ own total annual core throughput for the same period times the inventory, injection, and withdrawal storage capacity reserved for reliability/balancing purposes for SoCalGas’ total core market.  For instance, if a wholesale customer’s core throughput for the past 12 months was 10% of SoCalGas’ core throughput for the same period, the wholesale customer could elect to take 3.5 Bcf of inventory, 23.4 MMcfd of injection, and 193.5 MMcfd of withdrawal. Each wholesale customer would have to take the whole amount of storage so quantified, and not some portion thereof, if it chooses to exercise this option.  Wholesale customers exercising this option would pay the same rate per unit of storage as charged by SoCalGas for storage capacity reserved for its own core market.  Wholesale customers would have the opportunity to exercise this option once a year immediately before the annual storage open season, to be effective for a period of one storage year (April 1 to March 31 of the succeeding year).  Wholesale customers are under no obligation to exercise this option and may acquire storage capacity in the same manner as all other noncore customers whether or not they exercise this option.

5.5	Eliminate Core Subscription Service
5.5.1	Summary of D.99-07-015:  The Commission recommends elimination of core subscription service by PG&E and SoCalGas by April 1, 2001, and requiring that any noncore customer who prefers to continue procurement from those utilities after that date to take and pay for core transportation service as well as gas supply service.  The Commission does not recommend that SDG&E be required to exit its noncore procurement services.  (p.49, pp.63-64, Appendix C)
5.5.2	Current Status:  SoCalGas currently offers core subscription service under contracts with a two-year term.  SDG&E offers gas procurement service to noncore customers under both two-year core subscription contracts and one-month contracts.
5.5.3	Resolution:  SoCalGas will stop offering new core subscription contracts by April 1, 2001.  Beginning on the effective date of a Commission decision approving this Settlement Agreement (which is prior to the general effective date of the Settlement Agreement as a whole), SoCalGas will offer new core subscription contracts for a term that extends no later than July 31, 2001.  All core subscription contracts in effect on April 1, 2001 will remain in effect until the end of the contract life.  After April 1, 2001, all noncore-eligible customers must either choose a competitive provider for the commodity or take service from SoCalGas at core rates (GN-10).  SoCalGas will provide them with adequate advance notice of their choices.  SoCalGas will also provide these customers with a list of interested gas marketers operating on its system, so they can contact these marketers about their commodity choices.  
In the event that customers do not make a choice by the deadline, they will automatically become core customers (GN-10).  SoCalGas will continue to treat transportation revenues from these customers that switch to core status as noncore revenues (i.e., the revenues will be recorded in the NFCA and not the CFCA), until the switch from noncore to core is reflected in the throughput forecast in the next BCAP.
Both the Core Subscription option and the noncore procurement option are eliminated for SDG&E customers under the same terms described above for SoCalGas.  Exiting noncore procurement is consistent with the situation existing currently for both SoCalGas and PG&E.  By April 1, 2001 or at the end of existing contracts, whichever occurs later, all noncore customers in the SDG&E service area must choose a competitive provider for commodity.  SDG&E will provide them with advance notice of the change.  SDG&E will also provide those customers with a list of interested gas marketers, so they can contact these marketers about their choices.  
In the event that the SDG&E noncore customer does not make a choice by the deadline, the customer will automatically become a core customer.  If the customer becomes a core customer, it will take service from SDG&E at core rates, both core transportation and procurement rates.
5.6	Separate Costs and Rates for Core Utility [Procurement] Services.  Treat Utility Core Procurement Departments as Any Other Utility Customer
5.6.1	Summary of D.99-07-015:  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.   (p. 49 [#8], p. 62, p. 86, Appendix C)
5.6.2    Current Brokerage Fee:  Current SoCalGas brokerage fee is 2.0 cents/dth and SDG&E brokerage fee is 0.95 cents/dth, per the 1996 BCAP decision.  
5.6.3	Resolution:  The Core Brokerage Fee will be increased to 2.4 cents per decatherm for both SDG&E and SoCalGas upon the effective date of the settlement.  This is consistent with the brokerage fee for PG&E.  The parties further agree that the Core Brokerage Fee amount of 2.4 cents per decatherm is assumed for purposes of this Settlement only and shall be neither precedential nor admissible in any subsequent regulatory proceeding for the purpose of determining the actual costs that will no longer be incurred by the utilities in the event the utility core procurement service function is discontinued.  Unbundling is provided for elsewhere in this Settlement Agreement for SoCalGas interstate pipeline capacity, SoCalGas backbone transmission, SoCalGas storage for reliability (with some limits), SoCalGas core and noncore storage other than for reliability, SoCalGas balancing service.  Other provisions of this Settlement Agreement make SoCalGas’ and SDG&E’s departments providing core procurement service subject to the same balancing tolerances and rules as CTAs.

6.	INFORMATION  
6.1	Provide Real-Time, Customer-Specific Usage Data
6.1.1	Summary of D.99-07-015:  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, FoF 33 & 36, CoL 15-16, Appendix C) 
6.1.2	Current Status:  With regard to access to consumption and other customer-specific data by core customers or persons authorized by them to access information about them, the Parties are generally satisfied with the existing kind of core customer data maintained by SoCalGas and SDG&E, but are not satisfied with delivery options and data presentation.  Specifically, non-utility parties desire that SoCalGas and SDG&E modify their systems to present consumption data in consistent formats across different contexts (e.g., EDI billing of line items, imbalance statements to CTAs, historical statements for prospective CAT end-users).  Core customer consumption on the SoCalGas and SDG&E systems is not accessible on a real-time basis.  With regard to access by SoCalGas noncore customers, or persons authorized by them, to their own consumption data, consumption data is generally available on a daily basis.  Noncore customers also have the option, at their expense, to have SoCalGas install devices allowing real-time access to their consumption data.

6.1.3	Resolution for Core Customer Data:  With respect to core customers:  SoCalGas and SDG&E will allow access to, or provide to customers, or their agents, any existing information (not real-time metered consumption data, although forecast consumption for each CTA will be available daily from SoCalGas) regarding core customers’ own gas usage, including through Internet transactions.  SoCalGas and SDG&E are not required to make any changes to their current system and provision of customer-specific information, but will work with customers to meet their information needs.  Customers will pay the reasonable cost of any requests for additional information.
Further, SoCalGas and SDG&E agree to convene data access workshops with parties to reach agreement on improved access and delivery procedures by not later than sixty days after filing this Settlement Agreement.  Section 7.1 of this part of the Settlement Agreement includes provisions for a pilot program for core customers that will include a test of devices and systems that would allow core customers access to their own consumption data more often than the current monthly meter reading.

6.1.4	Resolution for Noncore Customer Data:  With respect to noncore customers, this Settlement Agreement requires SoCalGas to continue to offer services currently offered to noncore customers , as described below, for access to their own consumption data on a daily and on a real-time basis, and to make or offer improvements in this access as specifically described below.  Nothing in this Settlement Agreement prohibits SoCalGas at its discretion from making improvements in kind of information access provided or the systems providing the information.  This Settlement Agreement does not address real-time access to consumption of SDG&E noncore customers because it does not make any significant change in SDG&E’s rules or practices that would impact that subject.  However, nothing in this Settlement Agreement prevents the Commission from addressing during the term of this Settlement Agreement real-time access of SDG&E noncore customers to their own consumption data.
	6.1.4.1	Customer Options to Access Meter Data:  Presently, SoCalGas has approximately 2,000 customer meters outfitted with automated meter reading (AMR) devices which collect usage information necessary to bill SoCalGas’ noncore and large transportation customers.  Of this total, about 1,750 devices have telecommunications capability which allow them to automatically report meter usage to SoCalGas’ Measurement Collection System (MCS).  The approximately 250 remaining are stand-alone, non-communicating AMR devices, where usage information is downloaded manually on an as-needed basis.  These non-communicating AMR devices are typically used on meters with low or seasonal usage and on meters located in remote areas where telecommunications capabilities are not practical. 
For AMR devices equipped with telecommunications capability, SoCalGas’ Measurement Collection System automatically collects hourly usage, through either conventional telephone lines, radio, or cellular equipment.  Meter usage data for the previous 24 hours are collected by MCS between midnight and 4:00 a.m.  The MCS then uploads the data to SoCalGas’ GasSelect software between 4:00 a.m. and 6:00 a.m.  As a result of this process, usage data for the previous 24-hour period is generally available to customers after 6:00 a.m. via the internet using SoCalGas’ GasSelect software.  In addition, SoCalGas currently offers its customers options to directly access meter usage information through pulses provided at the metering site.
6.1.4.2	Dial-In Access to AMR Data:  SoCalGas currently offers customers an option to access their gas usage data by providing pulses, which can be converted into usage, through its Data Access Service.  Presently, there are approximately 140 customers utilizing this service.  Customers desiring this service need to execute a Data Access Service Agreement and an Agreement for Collectible Work with SoCalGas.  The data obtained through this option is not necessarily billing-quality-ready.
This service is available through the use of various electronic measurement devices.  The device is installed and maintained by SoCalGas at the customer’s expense.  This option enables customers to gain access to their gas usage more frequently than is provided by GasSelect or the normal meter read schedule.  SoCalGas is not responsible for any losses or damages incurred by the customer through the use of this service.
6.1.4.3	Internet Access to Full AMR Data:  SoCalGas’ GasSelect service enables customers and/or theirs marketers to access daily usage data for energy management purposes. GasSelect service is accessible via the internet at www.gasselect.com.
Subscribers to GasSelect service are subject to terms and conditions as established in SoCalGas Tariff Rule 33.  GasSelect service provides subscribers with access gas transportation services and information, including gas usage, nominations, allocations, confirmations, imbalance trades, storage transactions/balances, electronic bulletin boards, and e-mails.
6.1.4.4	Internet Information on Meter Access Options:  SoCalGas will expand its web site at www.socalgas.com to include a description of meter data access options.  SoCalGas will provide detailed information on the GasSelect software and the Data Access Service options.  Accessible information may address:  meter types, electronic measurement devices, AMR device types, system protocols, browser software requirements, subscriber’s hardware requirements, types and frequency of data provided, service fees/charges, sign-up procedures, and SoCalGas’ contact telephone numbers for access and inquiry.

6.2 	Provide Details of Completed Transactions 
6.2.1	Summary of D.99-07-015:  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. 73- 78, FoF 17, CoL 17, Appendix C)
6.2.2	Current Negotiated Transportation and Storage Contract Reporting Requirements:  SoCalGas posts any terms for discounted transportation or storage made to marketing affiliates on its GasSelect Electronic Bulletin Board pursuant to D.98-03-073 (Pacific Enterprises – Enova Corporation merger decision).  Long-term (five or more years) negotiated transportation contracts submitted under the EAD process may have some prices, terms or conditions redacted from public access for good cause.  Short-term (less than five years) negotiated transportation contracts are made available without redaction at the Commission and SoCalGas’ principal place of business within 5 days of signature, subject to the ability of SoCalGas to seek confidentiality of contract information pursuant to the regulations adopted in D.97-06-110.  SoCalGas also seeks Commission approval for all storage contracts under Schedule G-LTS via Advice Letter.  The Advice Letter which is available to the public includes the name of the customer purchasing the service; the time period for which the contract covers; the storage capacities purchased; and the rate charged.
Resolution: The resolution for backbone transmission and storage transactions is as provided below:
6.2.3.1:Transportation Contracts:  Nothing in this Settlement Agreement changes before October 1, 2001, existing reporting and disclosure requirements for negotiated transportation contracts.  For the period from October 1, 2001, through the end of the term of this Settlement Agreement, SoCalGas will file with the Commission and post on GasSelect a monthly negotiated backbone transmission contract report.  This report will list the details, but not customer names, of all negotiated capacity transactions for firm transportation, and interruptible backbone transportation.  Nothing in this Settlement Agreement changes nor prevents the Commission from changing existing reporting and disclosure requirements for negotiated contracts for transportation services other than backbone transmission service.  Nothing in this Settlement Agreement changes the reporting requirements for transportation transactions by SoCalGas with affiliates imposed by the energy utility affiliate transaction rules or the conditions imposed by the Commission in the merger of Pacific Enterprises and Enova Corporation (D.98-03-073).  Nothing in this Settlement Agreement prevents the Commission from changing the affiliate transaction rules or the Pacific Enterprises-Enova Corporation merger conditions as they apply to reporting of transportation transactions with affiliates. 
6.2.3.2:Storage Contracts:  Nothing in this Settlement Agreement changes for contracts in effect prior to April 1, 2001, the current requirements for reporting and disclosure of negotiated storage contracts.  For negotiated storage contracts in effect between April 1, 2001 and March 31, 2003, SoCalGas will file with the Commission and post on its GasSelect system a quarterly report open to the public on negotiated storage contracts in effect that lists the quantity, price and term (but not contracting party name) of all negotiated storage contracts.  For negotiated contracts in effect on and after April 1, 2003, SoCalGas will file and post on GasSelect the same information, but excluding the price.  Nothing in this Settlement Agreement changes the reporting requirements for storage transactions by SoCalGas with affiliates imposed by the energy utility affiliate transaction rules or the conditions imposed by the Commission in the merger of Pacific Enterprises and Enova Corporation (D.98-03-073).  Nothing in this Settlement Agreement prevents the Commission from changing the affiliate transaction rules or the Pacific Enterprises-Enova Corporation merger conditions as they apply to storage transactions with affiliates.
6.3	Establish a Secondary Market [Trading System] via a Utility Electronic 
Bulletin Board
6.3.1	Summary of D.99-07-015:  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)
6.3.2	Current Secondary Market Trading:  There is currently no secondary market trading of transmission rights on the SoCalGas or SDG&E system because no such rights exist.
6.3.3	Electronic Trading System Provisions:  SoCalGas will institute a system of electronic trading of backbone transmission rights in a secondary market as described below.  SDG&E will not do so pursuant to this Settlement Agreement because it does not establish such rights on the SDG&E system.  SoCalGas will facilitate a voluntary and anonymous secondary market trading system for firm backbone transmission capacity as part of its sole-source contract with ALTRA, and subject to the terms of that contract.  The following provisions will apply:
6.3.3.1	Firm transmission capacity by receipt point will be included on the electronic trading platform.  
6.3.3.2	ALTRA and SoCalGas will establish the process for reporting assignments, and ALTRA will provide the screens and trading platform.  
6.3.3.3	ALTRA will notify SoCalGas of the capacity assignment upon completion of a trade and SoCalGas will adjust its records accordingly and issue a new authorized nomination number to the assignee.
6.3.3.4	ALTRA will post on its electronic trading platform a summary of the completed transactions, listing the amount of capacity, the receipt point (for transmission), transaction price and the term of the assignment.  Customer names will not be provided.
6.3.4	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.  SoCalGas will receive fifty percent (50%) of the transaction fees to cover its ongoing costs and services.  The fifty percent received by SoCalGas will be subject to the provisions of Section 1.6 of Part I (Introduction) of this Settlement Agreement.
6.4	Provide Pipeline Operator Demand Forecasts Broken Down By Customer Class
6.4.1	Summary of D.99-07-015:  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)

6.4.2	Current Status:  SoCalGas currently makes available on its GasSelect system on a daily basis substantial detailed information about its gas system operations.
6.4.3	Resolution:  This Settlement Agreement requires SoCalGas to post operating information that is at least as extensive as PG&E is required to post pursuant to its OFO settlement filed on October 22, 1999, in I.99-07-003, and since approved by the Commission.  A detailed description of this Settlement Agreement’s requirements for posting of OFO-related information by SoCalGas is set forth in Appendices C and D to this Settlement.  In addition, during each summer season (generally, April through October), SoCalGas will provide on an after-the-fact basis on its GasSelect system sufficient data by customer class (core, noncore non-generation, and noncore generation) to allow parties to analyze the reasons that particular OFOs were called by SoCalGas.

7.	REVENUE CYCLE SERVICES
The Parties note that Southern California Edison is neither subscribing to nor opposing this Section 7 of this Settlement Agreement.
7.1	Provide for Competitive Metering Technologies

7.1.1	Summary of D.99-07-015:  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)
7.1.2	Ownership of Meters and Add-on Devices: Consistent with obligations under existing law, the utilities 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 commercial, industrial and master-metered multifamily customers may own their own utility-approved meters, or may choose meters to be owned by the utilities, for new meter installations.  Further, also as a pilot program, a limited number of customers may own an "add-on device" to the utility-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 its Core Aggregator or Supplier.  The selection and installation of this add-on device must also comply with established standards and procedures.

SoCalGas and SDG&E will conduct pilot meter and add-on device ownership programs.  The pilot programs will extend through 2002.  By July 1, 2002, SoCalGas and SDG&E will submit a joint evaluation of the pilot programs and recommendations for 2003 and beyond.
During the pilots, customers may own gas meters and add-on devices so long as the meters and devices meet SoCalGas’ or SDG&E’s standards for safety and the add-on devices are compatible with utility meters and data retrieval processes as determined by the utilities.  SoCalGas or SDG&E will install, maintain, test, collect and process data from and provide all related services associated with all gas meters, regardless of who owns the meter.  Likewise, the utilities shall install, maintain, test, and provide related meter services for add-on devices, but customers may collect and process data from their own add-on devices as long as it does not interfere with utility access for billing purposes.   The following principles provide the basis for the pilot ownership programs and to help guide implementation.
•	All customer-owned meters and add-on devices will have to meet appropriate standards of safety, accuracy and reliability, as determined by the utilities.  
•	Customer ownership of any meter or add-on device will not interfere with the utility's right to obtain current or additional data from the meter.  The utility also reserves the right to reconfigure the meter to improve the utility's ability to obtain current or additional data.  For example, if the utility chooses to install automated meter reading (AMR) technology for a new class of customers or a given portion of its service area, the utility 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 the utilities. 
•	Those customers that choose to own their own meters or add-ons are responsible for the additional incremental capital and O&M costs associated with such equipment including communication network costs.
•	Costs to revise the utility systems to track customer meter ownership and add-on devices, to the extent they are not currently recovered in rates, will be recovered through the cost recovery process described in this Settlement Agreement.
•	Nothing in this Settlement Agreement prevents the utilities 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 utility proposals to offer any such new meter or meter-related products and services during the term of this Settlement Agreement.
a.      Pilot Program for Customer Meter Ownership and Meter Choice:  The following provisions apply to this pilot program for limited meter ownership and choice of the utility-owned meters.
•	Participation Limit:  The pilot program is limited to the installation of 500 customer-owned meters per year for SoCalGas and 200 customer-owned meters for SDG&E.  The pilot program applies only to new meter installations at customer facilities which require gas meters of 500-cubic-feet-per-hour capacity or larger to meet customer load requirements.  These customer facilities are commercial, industrial and master-metered multifamily dwellings.  The pilot does not provide for the replacement of an existing utility-owned meter.  The utility at its sole discretion may increase the cap on the number of meters that can be owned by customers.
•	Limit on Meter Choice:  The meter ownership pilot program is limited to customer ownership of meters that are compatible with the utility’s Meter Set Assembly (MSA) designs and approved by the utility.  Nothing in this program requires the utility 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 the utility from removing currently-approved meters from the approved list.  
•	Cost Responsibility:  Customers choosing to own their meter are responsible for incremental costs associated with their meter that are incurred by the utility.  Incremental costs are those costs beyond the costs that would have been incurred by the utility 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,  communication network costs, and any other incremental transaction-based costs associated with their owning the meter. 
•	Utility Access to Meter Data:  The utility has the right to obtain or directly access any data available from the customer-owned meter.  The utility may also install add-on devices to a customer-owned meter which do not interfere with the customer’s use of that meter.  The utility would pay the cost of such add-ons.
•	Advice Filing for Pilot:  The utilities 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 this Settlement Agreement.  
•	Term of Pilot:  This pilot program is effective when the CPUC-approved tariffs implementing this program are effective, and will continue for the term specified in this Settlement Agreement, to December 31, 2002.  
•	Assessment of Pilot:  One year prior to the completion of the program,  the utilities 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.
b. 	Pilot Program for Customer Ownership of Meter Add-Ons:  Subject to the following terms and conditions, the utilities will allow a limited customer ownership of add-on devices to the utilities-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.
•	Participation Limit:  This pilot program is limited to the installation of 1,500 customer-owned meter add-on devices per year for SoCalGas and 200 customer-owned meter add-on devices for SDG&E.  The utility at its sole discretion may increase the cap on the number of customer-owned meter add-on devices.
•	Standards and Requirements: All customer-owned add-on devices will have to meet appropriate standards of safety, accuracy, reliability, and compatibility with utility meters and data retrieval, if necessary, as determined by the utility.  The utility shall develop such standards with input from interested parties and subject to oversight by the Commission.
•	Meter Responsibility:  Add-on devices will not adversely affect the safety, reliability and accuracy of the utility's gas meters, nor the utility's ability to obtain any meter data.  The utility remains responsible for installation, removal, service and maintenance of the add-on devices.  Customer ownership of an add-on device will not prevent or interfere with the utility's ability to replace or reconfigure the meter.
•	Cost Responsibility:  Customers will be responsible for the costs associated with add-on devices, including, but not limited to, installation, maintenance, removal, communication network costs, and any other transaction-based costs associated with that add-on device.  
•	Advice Filing for Pilot:  The utilities 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 this Settlement Agreement. 
•	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 specified in this Settlement Agreement, to December 31, 2002.
•	Assessment of Pilot Program:  One year prior to the completion of the program, the utilities 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.
c.   SDG&E AMR Program.  Nothing in this Settlement shall prevent SDG&E from proposing a pilot program for utility-owned AMR devices for gas meters in connection with any electric AMR pilot that SDG&E may propose; nor shall anything in this Settlement prevent any party from opposing such a pilot program.
7.2	Provide Competitive Billing Options to Customers Similar to Those Offered in the Electric Industry
7.2.1	Summary of D.99-07-015:  The Commission states that competing gas and electric providers should be able to choose to provide a consolidated bill 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 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)

7.2.2    Current Billing Options:  Currently, CTAs who sell gas to residential and small commercial customers have two options open to them.  They can bill for the gas commodity and have SoCalGas and SDG&E bill for gas transportation.  This is called separate billing.  The second option is for the CAT to bill for both their gas service and transportation service.  This option is called CAT consolidated billing.
A third potential billing option, utility consolidated billing, where SoCalGas or SDG&E bill for both  transportation service and the CAT’s gas commodity, is not available.  This third option is available to Energy Service Providers (ESPs) on the electric side.
Another difference between the electric side and the gas side is that currently, if a CAT performs CAT consolidated billing the utility still is required to send the customer an information-only bill, creating unnecessary billing costs to the utility.  No such requirement currently exists on the electric side. 
Other differences related to billing between EIR and CAT are related to information and timing standards.  There are specific standards that are in place for EIR that are not in place as part of the CAT program.  Specifically, standards for EDI billing, bill adjustments, account maintenance, measurement timing, and accuracy standards.
Finally, in electricity, a customer can receive credits off its transportation bill if the customer’s ESP performs ESP consolidated billing based on the costs the utility no longer has to incur.  There are currently no such credits on the gas side.

7.2.3    SoCalGas or SDG&E Consolidated Gas Billing:  SoCalGas and SDG&E may offer a consolidated billing option to CTAs as soon as billing system modifications allow it.  Details of this billing option (including standards for EDI billing, bill adjustments, account maintenance, measurement timing, accuracy standards, collection procedures and any fees to CTAs for consolidated billing related services) will be filed with the Commission in the advice letters implementing this Settlement Agreement.  Further, the gas utility consolidated billing standards and requirements should generally mirror the electric utility billing standards and requirements as closely as possible. 
7.2.4    Termination of Information-only Bill Requirement:  If a CTA performs CAT consolidated billing, SoCalGas and SDG&E are currently required to send the customer an information-only bill.  Parties agree that the requirement for an information-only bill should be removed upon the effective date of this Settlement Agreement for those CTAs who provide consolidated CAT billing to their customers and agree to provide monthly SoCalGas or SDG&E transportation charges and rate data, along with the  requisite bill inserts and customer protection materials, in each end-user bill.  The requirements should generally follow the requirements for consolidated ESP billing in the electric industry.

The CTA shall indemnify SoCalGas and SDG&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 utility-provided bill insert.  Any disputes concerning the content of a utility-provided bill insert will be resolved solely by the Commission, and the recommendation for resolution by the Commission shall be processed by the Energy Division of the Commission.  Nothing in this Settlement prevents other divisions of the Commission from participating as parties to this resolution process.  As part of its advice letters to implement this Settlement Agreement, SoCalGas and SDG&E will include provisions specifying compliance monitoring, cost responsibility, and enforcement measures.  
7.2.5   Avoided Cost Credits:   Customers of a CTA, which performs consolidated CAT billing, should receive a credit on their monthly bill for transportation service.  For SoCalGas, the avoided cost credits will be $0.78 for residential customers and $1.16 for non-residential customers.
For SDG&E, the avoided cost credits will be $0.05 per bill for residential customers and $0.16 for non-residential customers for a CAT gas bill where SDG&E continues to supply an electric bill.  Where the CTA/ESP is providing consolidated billing for both gas and electric service to an SDG&E customer, the numbers above would be in addition to the Commission approved credits for ESP consolidated electric billing for an electric only customer.
The parties agree that the level of the agreed upon billing credits is assumed for purposes of this settlement only and shall be neither precedential nor admissible in any subsequent regulatory proceeding for the purpose of determining the avoided cost billing credits for SoCalGas and SDG&E.
The level of the CTA and CTA/ESP billing credits provided above for SoCalGas and SDG&E shall be fixed for the period from the effective date of this Settlement Agreement through December 31, 2002, and are only applicable to customers whose information only bill has been discontinued in accordance with Section 7.2.4.  The Parties agree to undertake discussions and, if necessary, to litigate the appropriate level of these billing credits in such a manner that new avoided cost billing credits for SoCalGas and SDG&E will become effective January 1, 2003.  If the above-referenced discussions fail to produce an agreement by December 3l, 2001, SoCalGas and SDG&E shall file applications with the Commission in the first quarter of 2002, such applications to be consolidated, proposing for Commission approval a new level of avoided cost credits for implementation on a timely manner on January 1, 2003.
7.2.6    Delivery of CAT Consolidated Gas Billing Credits: The display of billing credits on the bill should be consistent with the methods used in electric restructuring to avoid customer confusion.  SoCalGas and SDG&E will deliver credits to those customers receiving consolidated billing services from their respective CTAs as a line item on SoCalGas or SDG&E’s customer-specific billing data provided to CTAs and shown on their consolidated bill to these customers as soon as the billing system changes can be made.  
Until the billing system changes can be completed, SoCalGas and SDG&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 SoCalGas and SDG&E deem most cost-effective, except that SoCalGas and SDG&E will deliver such checks on at least a semi-annual basis.  

III.	NO ISSUES REMAIN TO BE LITIGATED IN I.99-07-003
Parties agree that there are no issues of material fact or promising options which need litigating in I.99-07-003 as applied to SoCalGas and SDG&E, provided the Commission approves this Settlement Agreement pursuant to its conditions.  Parties note that this Settlement Agreement provides for certain implementation processes subject to Commission approval to implement this Settlement Agreement.  Also, this Settlement Agreement provides for certain issues to be the subject of future proceedings at a specified times after the approval of this Settlement Agreement.

If Commission approval of this Settlement Agreement 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.

[Conclusion of Main Text of Settlement Agreement.  Signature pages follow.]