III. Discussion

In D.01-12-018, the Commission adopted a CSA that modified the market and regulatory framework for regulating the transportation and storage of natural gas on SoCalGas' system. This decision adopts tariffs that implement D.01-12-018. This decision does not establish new polices and does not modify either the CSA or D.01-12-018.

The tariffs SoCalGas filed on July 15, 2003, as modified by the changes contained in Appendix B implement D.01-12-018 and should be approved. SoCalGas is ordered to file an advice letter within 10 days that should become effective the first day of the month at least three and one-half months after the effective date of this decision. SoCalGas should take steps to implement such tariffs by the first day of the month at least three and one-half months after the effective date of this decision.

Although we have reviewed all the tariffs filed by SoCalGas, this decision does not explicitly review and discuss each tariff page. Instead, we limit our discussion to contested tariffs. We have reviewed the uncontested tariff sheets, we find such tariffs to reasonably implement D.01-12-018.⁵ Below we address the implementation issues raised by parties.

A. Issues

1. Storage Service Issues

a) Timing of Implementation for Storage Services

SCGC contends that SoCalGas' tariffs⁶ evade the "timetable for phasing-in" of storage rates and revenues. SCGC states that the CSA provides a three-year phase-in of storage rates and revenue retention. Edison similarly opposes SoCalGas' proposal to be at 100% risk for the difference between unbundled storage costs and revenues from unbundled storage service. Edison states the purpose of the dates in the CSA was to provide a phased implementation of the risk during the implementation of unbundling, in order to give markets a chance to mature.

SoCalGas responds that the CSA contemplated that SoCalGas would be 100% at risk/reward for unbundled storage by April 1, 2003, through the remainder of the CSA period (until August 31, 2006). SoCalGas argues that its tariffs provide for storage rates and revenues consistent with the schedule contained in the CSA.

The issues raised by the parties arise from the fact that implementation of D.01-12-018 has been delayed. SCGC relies on language describing a "transition period" of rates and revenues. SoCalGas relies on a literal reading of dates contained in the CSA. In deciding which approach to follow, we examine the merits of each approach.

The CSA states that:

"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."

The analyses of SCGC and Edison are silent on the fact that approximately two years and eight months remain before the CSA expires on August 31, 2006. SCGC does not address how SoCalGas will receive the benefits it may have envisioned from the last four years of implementation of the CSA. At the same time, SoCalGas' analysis does not mention the two-year "transition period," and instead follows the literal language of CSA Section 2.3.3 which states that:

"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."

We believe that given the delay in implementation, the approach proffered by SoCalGas makes the most sense and is the most consistent with the intent of the CSA. SCGC's protest may have carried more weight had it proposed to extend the CSA or even prorate the transition period. However, neither of these proposals was presented and we will not pursue them. The intent of the CSA is to place SoCalGas at 100% risk/reward. In achieving that end, the CSA provided for a "transition period." Under SGCG approach greater emphasis is placed on transitioning rather than achieving the goal of placing SoCalGas at 100% risk/reward. We consider the CSA's intent to shield ratepayers from risk after a two-year transition period. Under SoCalGas' approach, ratepayers are shielded from risk whereas under SCGC's approach ratepayers are exposed to revenue shortfall risk for two years. Moreover, other than relying on the phrase concerning a "phase-in," SCGC and Edison did not demonstrate how signatories to the CSA or ratepayers would be harmed by moving to 100% risk/reward as envisioned and intended by the CSA. For all the foregoing reasons, we agree with SoCalGas' schedule for implementing storage services.

b) Schedule G-PAL

SCGC raises concerns about schedule G-PAL similar to the concerns raised above about timing of implementation of storage services. SCGC argues that schedule G-Pal offers services (gas parking and loaning services) that are "effectively storage related." Consequently, SCGC contends that the three-year schedule for deregulating rates and for permitting 100% revenue retention should apply to schedule G-PAL. Since we rejected SCGC's implementation timing proposal for implementation of gas storage services, we similarly deny SCGC's proposal for the treatment of schedule G-PAL.

c) Variable Charges for Storage
Services

SCGC contends that SoCalGas' proposed storage tariffs for implementing the CSA would impose variable charges for off-peak storage injection and withdrawal services that are not authorized by the CSA. Section 2.1.3.4 of the CSA addresses, among other matters, variable charges for storage capacity sold during the "open season" and Section 2.1.3.5 addresses, among other matters, variable charges for storage capacity not committed during the open season.

With regards to storage capacity not committed during the open season, SCGC believes that CSA Section 2.1.3.5 requires SoCalGas to apply the same terms as "existing" tariff schedules for unbundled storage capacity sold. Further, SCGC argues that the "proposed" tariffs of SoCalGas conflict with "existing tariffs." The "proposed" tariffs of SoCalGas permit variable charges for off-peak storage injection withdrawal services whereas "existing" tariffs do not.

We agree with SCGC concerning the application of variable charges for storage capacity not committed during the open season. CSA Section 2.1.3.5 clearly requires SoCalGas to apply the same terms as "existing" tariff schedules for unbundled storage capacity sold. CSA Section 2.1.3.5, in relevant part, unambiguously states that:

"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 the price floors and ceilings set forth above." (Emphasis added.)

Consequently, SoCalGas may not charge variable charges for storage services during off-peak consistent with existing schedules G-TBS, G-LTS and G-BSS.

With regards to storage capacity sold during the open season, no explicit language concerning the application of existing tariffs if found in Section 2.1.3.4 of the CSA. Instead, CSA relies upon a single word, "continue," in Section 2.1.3.4 for the proposition that tariffs existing at the time the CSA was executed should govern charges for storage capacity sold during the open season. We disagree. The signatories to the CSA clearly possessed the ability to articulate such a result as discussed above for storage services not committed during the open seasons and did not do so. Rather, Section 2.1.2.4 in relevant part, contains language that permit the imposition of variable charges.

"This rate [for unbundled storage service] 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 charge and variable rates would continue to be charged for actual usage in addition to this rate." (Emphasis added.)

Pursuant to Section 2.1.3.4 of the CSA, SoCalGas may impose variable charges for off-peak storage injection withdrawal services for capacity sold during the open season.

2. Information Disclosure Issues

In their comments, both SCGC and Edison raise concerns about the sufficiency of information SoCalGas proposes to disclose concerning covered transactions.

a) Negotiated Storage Contracts

(1) Schedules G-BSS and G-LTS

SCGC contends that Section 6.2.3.2 of the CSA requires SoCalGas to post on its electronic bulletin board a quarterly report that includes the quantity, price and term (but not contracting party) of all negotiated storage contracts. SCGC argues that SoCalGas fails to comply with Section 6.2.3.2 because in Schedules G-BSS and G-LTS, SoCalGas does not report on negotiated storage contracts.

SoCalGas does not believe it is required to post storage contract information pursuant to Schedules G-BSS and G-LTS because these two storage contracts will be closed to new customers upon CSA implementation. However, in its reply brief, SoCalGas states that it is willing to accommodate the request of SCGC to report information concerning Schedules G-BSS and G-LTS.

SCGC raises the issue of whether information should be disclosed for existing negotiated contracts when the schedules will be closed to new customers. We observe that the CSA acknowledged prior Commission concerns (D.99-07-015) that "disclosure of transaction-specific details about storage contracts is basic and fundamental to an efficient market." (CSA at Section 6.2.1.) Given that the Commission and the signatories to the CSA expressed an intent that transactional information should be disclosed, we are inclined to find that such information should be disclosed. We will accept SoCalGas' offer in its reply brief to report information for contracts under Schedules G-BSS and G-LTS and do not need to pursue this matter further.

(2) Disclosure of Price Information

SCGC complains that SoCalGas does not intend to comply with the posting requirements of Section 6.2.3.2. SCGC asserts that the CSA requires SoCalGas to post information about price, quantity and term, but that SoCalGas proposes to omit information about price.

SoCalGas responds that SCGC is seeking information beyond what is required by the CSA. In support of its position, SoCalGas cites Section 6.2.3.2 of the CSA which states in relevant part that:

"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 any 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 price." (Emphasis added.)

SoCalGas believes that the above language makes clear that for "contracts in effect on or after April 1, 2003," SoCalGas is not required to post information concerning price. SCGC responds that SoCalGas is ignoring the two-year phase-in schedule adopted in the CSA and should report quantity, price and term.

The issue raised by SCGC is a timing issue that arises from the fact that implementation of the CSA has been delayed. We find that both parties are in part correct. SCGC correctly observes that SoCalGas is bypassing the phase-in anticipated in the CSA. However, under SCGC's approach, Section 6.2.3.2 is only half implemented because time will run out prior to SoCalGas being excused from having to report prices. SCGC does not address this inequity. SoCalGas is also correct in that it is following the explicit reporting instructions for negotiated contracts in effect on and after April 1, 2003.

In this instance, we find that the intention of the parties pursuant to the CSA was to promote an efficient market. In doing so it appears that the parties balanced the need for information in a marketplace with confidentiality concerns. In this instance, withholding price information as proposed by SoCalGas may have a detrimental effect in promoting an efficient marketplace. We are guided by the principle that disclosure of transaction specific details about contracts is basic and fundamental to an efficient market. Unlike our resolution of timing for implementing storage services, here we find the phase-in period anticipated in the CSA may be essential for the development of an efficient marketplace. Since the CSA does not explicitly state why the posting of price information is not necessary after two years, we can only infer that once information for existing negotiated contracts is published the contribution of such information in the future to the development of an efficient marketplace may diminish. Consequently, we reject SoCalGas' proposal to withhold price information concerning negotiated storage contracts. Pursuant to Section 6.2.3.2 of the CSA, SoCalGas should post information about price, quantity and term of storage contracts.

b) Storage Transactions in the
Secondary Market

With respect to storage transactions in the secondary market, SCGC argues that SoCalGas should post the price but not the names of participants. In support of its position, SCGC cites Section 6.3.3.4 of the CSA which states that "transaction price" will be posted but that "customer names will not be provided." Edison also believes that SoCalGas should post all the information required by Section 6.3.3.4 of the CSA.

SoCalGas agrees with SCGC's interpretation of Section 6.3.3.4 of the CSA, but contends that D.01-12-018 modified the CSA. The relevant passage from D.01-12-018 is as follows:

This system of firm tradable storage rights would be established together with a secondary market for the trading of those rights. In Section 2.2.3, the CSA provides that customers who have purchased SoCalGas' unbundled storage may assign 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. SoCalGas will facilitate a voluntary and anonymous secondary market trading system via an electronic bulletin board for the storage contract trading. However, the bulletin board need not be used for trading - traders can contact each other. While price is not disclosed without approval of the parties, the parties and term of the assignment will be public. The SoCalGas GasSelect System is the interim trading mechanism under the CS. (D.01-12-018 at 57-58, emphasis added.)

SCGC disagrees that the Commission was attempting to modify the CSA. Instead SCGC believes that in the passage quoted above the Commission was reciting the contents of the CSA. In support of its position, SCGC argues that the CSA consistently requires that SoCalGas keep names, not price, confidential.

SCGC recommends that the Commission direct SoCalGas to publish the amount, price, and term of secondary storage transactions while keeping the names of parties confidential, absent approval of publication of names by the involved parties.

We agree with SCGC that the paragraph cited by SoCalGas represents an erroneous recital of the CSA's intent. In viewing D.01-12-018 as a whole document, it is clear that the Commission made efforts to highlight changes it was making to the CSA and further reflected most of these changes in the findings of fact or conclusions of law. In the instant situation, the paragraph cited does not explicitly inform the reader the Commission is making a modification to the CSA, clearly explain the modification or discuss a rationale for making the modification. In this instance, a discussion concerning the policy basis for disclosing names but not price should have been included in light of the fact that such a change would have created an inconsistency. Moreover, D.01-12-018 contains no finding of fact or conclusion of law that indicate that the Commission modified the CSA concerning disclosures for storage transactions in the secondary market. Read as a whole document, we disagree with SoCalGas' interpretation and modify SoCalGas' tariffs so that price but not names of parties are disclosed for storage transactions in the secondary market.

c) Tariffed Rate Storage Contracts

SCGC requests that the Commission require SoCalGas to post information about amount, price, term and names for storage services at tariffed rates under Schedules G-CGS or G-PAC. SCGC states that neither the CSA or SoCalGas' tariff sheets provide for disclosure of such information and that such a step would go beyond the CSA and scope of this proceeding. However SCGC contends that such a change is warranted as a matter of policy.

We do not address the merits of SCGC's request. We deny SCGC's request on the ground that it goes beyond what is required by the CSA and is also outside the scope of this proceeding as acknowledged by SCGC itself.

3. Tariff Schedule G-BR

SoCalGas' proposed Schedule G-BR implements some of the main features of the CSA such as the unbundling of the SoCalGas backbone transmission service from local transmission and distribution service and the establishment of firm receipt point rights. Under Schedule G-BR, SoCalGas would provide firm and interruptible receipt point rights and transmission service on its backbone transmission system.

a) Set-Aside Rights

Prior to conducting an initial open season for firm receipt point capacity, Sections 1.1.3.5 and 1.9 of the CSA require SoCalGas to "set-aside" capacity for certain customers. In its testimony, Edison proposes that it receive set-aside rights based on forecasted usage due to concerns about its ability to acquire sufficient gas given its new responsibilities for obtaining gas for electric generator facilities.

SCGC opposes Edison's request as outside the scope of this proceeding. SCGC contends that it would be patently unfair to consider Edison's allegations of changed circumstances while denying other parties the opportunity to address issues that go beyond implementing the CSA.

The CSA is clear concerning set-aside rights. The CSA provides no exemption for Edison to receive set-aside rights based on forecasted usage. Edison's request for set-aside rights should be denied.

However, Edison raises a concern about its ability to acquire sufficient bidding rights to administer contracts on behalf of the State Department of Water Resources (DWR). At hearing a witness for SoCalGas offered a simple solution. The SoCalGas witness testified that under the CSA an end-use facility could assign its rights based upon historic use to the entity supplying the gas.⁷ Further, SoCalGas witness stated that it expected that such arrangements would be part of normal commercial agreements between parties.⁸ Although both Department of General Services (DGS) and Edison raise concerns about Edison's ability to acquire sufficient bidding rights to administer CDWR contracts, neither party introduced such contracts or relevant portions of such contracts to show that an actual conflict with the CSA existed. Since neither DGS nor Edison submitted any evidence concerning what rights, if any, were acquired from generators it is difficult to address Edison's situation. Edison's request in its opening comments that historic tolling rights be considered a reassignment of bidding rights is reasonable and consistent with the manner SoCalGas indicated it would implement the CSA. Since a witness for SoCalGas testified that SoCalGas would implement the CSA in a manner that would allow Edison to receive assignment of historic bidding rights from generators it intends to serve we see no need to modify the CSA at this point in time.

b) ExxonMobil Request for Set-Aside
Rights on the North Coastal System

ExxonMobil Gas & Power Marketing Company (ExxonMobil) asserts that it should receive set-aside rights of up to 68.8 MMcf/day at the North Coastal receipt point, but that SoCalGas has excluded ExxonMobil from receiving such set-aside rights. ExxonMobil states that its gas is delivered directly from the Pacific Offshore Pipeline Company (POPCO) facility into the SoCalGas system through the North Coastal line. In support of its position, ExxonMobil relies upon Section 1.1.3.6 and Appendix B of the CSA.

Section 1.1.3.6 of the CSA provides in relevant part for

"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."

Appendix B of the CSA provides in relevant part as follows:

"Existing on-system California producers can obtain up to 100% of the North Coastal and Line 85 receipt point capacity rights based on their historic deliveries."

ExxonMobil contends that its "historic deliveries" to the North Coastal receipt point are 68.8 MMcf/day. ExxonMobil complains that Schedule G-BR, Special Condition 28, Sheet 10, which describes set-aside rights for "California Producers connected directly to Line 85, North Costal (excluding ExxonMobil Corp.)" improperly excludes ExxonMobil from receiving set-aside rights. ExxonMobil contends that the CSA provides all California on-system producers, including ExxonMobil with set-aside rights equal to their historic deliveries and nothing in the CSA excludes ExxonMobil from receiving set-aside rights as proposed by SoCalGas.

In response, SoCalGas states that insufficient capacity rights exist to grant ExxonMobil the firm set-aside rights it claims without reducing the set-aside rights of core customer and other California producers. SoCalGas asserts that 120 MMcf/d of firm capacity rights exists on the North Coastal system under the CSA and since the CSA grants 73 MMcf/d of firm set-aside rights to core customers, it is impossible to grant ExxonMobil set-aside rights for 68.8 MMcf/d.

The Office of Ratepayer Advocates (ORA) states that the North Coastal line has a capacity of 120 MMcf/d and that D.01-12-038 reserved 73 MMcf/d for the core. ORA observes that at the time the CSA was negotiated SoCalGas had a contractual agreement with Pacific Offshore Pipeline Company (POPCO) for purchase of core gas supplies. ORA states the POPCO contract had a December 31, 2003 termination date and that in recognition that the POPCO contract was terminating, the CSA reserved 70 MMcf/d of North Coastal capacity for core customers.⁹ ORA has no objection to ExxonMobil receiving a set-aside of 68 MMcf/d and eliminating the core's set aside of North Coastal capacity as long as the CSA is modified to permit the core to receive 73 MMcf/d set-aside capacity at Wheeler Ridge.

The issue raised by ExxonMobil is whether the CSA grants it set-aside rights of 68 MMcf/d. We agree with SoCalGas and ORA that the CSA is unambiguous concerning the set-aside of 73 MMcf/d of North Coastal capacity for core customers. The CSA also clearly defines firm capacity available at each receipt point; in the case of North Coastal, that amount is 120 MMcf/d. ExxonMobil's interpretation of the CSA creates a clear conflict in assigning 73 MMcf/d of North Coastal capacity to core customers. Since backbone transmission rights are defined as the firm right to have SoCalGas redeliver gas at a specific receipt point path, the total aggregate of backbone transmission rights cannot exceed the capacity available at each receipt point. Under ExxonMobil interpretation of the CSA insufficient capacity exists at North Coastal to provide ExxonMobil with the 68 MMcf/d of capacity it requests.

ExxonMobil's request for a set-aside is not supported by the CSA and should be denied. However, ExxonMobil may bid for capacity in the open season consistent with this decision and the open season process described in the CSA.

c) Market Concentration Limits

Edison requests an exemption from the CSA requirement concerning the maximum limit of 30% of receipt point capacity that an end-use customer may hold at any given receipt point at the end of an open season. Edison asserts that it needs an exemption to obtain sufficient full access rights in the open season to meet its demands. In support of its position, Edison argues that absent the exemption it might have to buy receipt point capacity in the secondary market, capacity from SoCalGas, gas at city gate or interruptible capacity at a cost substantially higher than meeting demand through set-aside rights. Edison asserts that this exemption is warranted because (1) such higher costs would harm its customers and (2) there are changed circumstances pertaining to Edison's duty to administer California Department of Water Resources (CDWR) contracts.

SCGC and California Manufacturers and Technology Association (CMTA) oppose Edison's proposed exemption from market concentration limits. SCGC believes that Edison's request for an exemption from the 30% market concentration limit is unnecessary, unsupported, and inconsistent with the CSA. CMTA emphasizes that customers who require more capacity than their historic rights can obtain it through the secondary market. SoCalGas takes no position, but believes that the exemption requested by Edison is unsupported by the CSA and may detrimentally affect other customers by decreasing the amount of backbone capacity that is available to other customers at desirable receipt points

In deciding whether to grant an exemption to Edison, we observe the purpose of the market concentration limit is to prevent market power abuse. In D.01-12-018, we stated that:

"We support the adoption of a market concentration limit, but we agree ... that the 40% limit is too generous. ...We acknowledge that the cap represents less than 40% of the total capacity at each receipt point, but we believe that the limit should be set slightly lower to prevent any abuse of market power. Therefore, we will modify the market concentration limit such that no person can hold more than 30% of the capacity at each receipt point that has not been awarded to the [SoCalGas] Gas Acquisition Department, CTAs, or wholesale customers using their reservations. ... We decline to adopt a market concentration limit to capacity acquired through the secondary market at this time. Instead we caution parties that if we find that secondary market transactions result in a concentration of capacity held by individuals entities or marketers, we will open an investigation to revisit the market structure adopted in this decision." (D.01-12-018, mimeo. at p. 45.)

We agree with SCGC that Edison's request for an exemption from the 30% market concentration limits adopted is unsupported and inconsistent with the CSA. We also see no inconsistency as suggested by Edison. On its face, the CSA as modified by D.01-12-018, is clear about the market concentration limits imposed and the basis for such limits. As CMTA points out, to the extent Edison is unable to procure sufficient capacity through set-aside rights, the secondary market exists to meet demand. Lastly, the main basis for implementing market concentration limits as described in D.01-12-038 was to protect against any abuse of market power. In fact, after careful consideration, the Commission actually reduced the 40% limitation set forth in the CSA to 30%. Edison has not adequately addressed how its proposed exemption would affect the policy of protecting against market abuse that underlies the market concentration limit.

d) Open Season Bidding Rights

Edison seeks bidding rights in excess of historical usage. In Tariff Schedule G-BR, Sheet 11, SoCalGas has proposed to define bidding rights based on the use of forecasted demand when the customer can justify a load change from historical demand. In Schedule G-BR, SoCalGas as an "accommodation" allows a customer such as Edison to attain bidding rights based on forecasted usage. In its opening brief, Edison states that it agrees with the proposed language.

CMTA, Watson Cogeneration Company (Watson), and SCGC oppose granting bidding rights based on forecasted usage as inconsistent with the CSA. CMTA states that neither Edison nor electric generators are entitled to bidding rights based on forecasted demand.

In its reply brief, SoCalGas acknowledges that:

"Only existing noncore customers are entitled to bid for backbone capacity in the open season, and only to the extent of their historical load. These customers are permitted to assign their bidding rights to a third party." (SoCalGas reply brief at p. 39.)

Nonetheless, as an "accommodation to the parties, SoCalGas proposes to allow certain, limited adjustments to bidding rights when a customer's historical load does not properly reflect future needs." With respect to Edison's request to obtain additional bidding rights, SoCalGas states that the CSA does not afford Edison these rights. Although SoCalGas agrees with other parties that Edison does not qualify under the CSA for additional bidding rights, SoCalGas takes no position on this issue. In addition, SoCalGas provides the disclaimer that any accommodation for Edison will decrease the amount of backbone capacity that is available to other customers at desirable receipt points.

Although SoCalGas takes no position on granting bidding rights for Edison and other customers based on forecasted usage, we agree with SoCalGas' analysis of the CSA and concerns of SCGC and CMTA. The scope of this proceeding has been limited to implementing the CSA while concerns about changed circumstances have been deferred to a future proceeding. It would be patently unfair if we were to entertain changes to the CSA for some parties and not for others. Consequently, we reject SoCalGas' proposal to determine bidding rights based on forecasted usage or any other manner not consistent with the CSA. We will modify schedule G-BR so that bidding rights are established based on historical consumption and not on forecasted usage.

e) Seasonal Usage

SCGC raises concerns about how SoCalGas has implemented Section 1.1.3.6.1 of the CSA which addresses the first stage of the initial open season and in relevant part states:

"Customers' maximum bidding rights shall be determined by a formula that fairly balances seasonal and annual usage."

In response to these concerns, SoCalGas proposed a formula that assigns bidding rights to customers that have seasonal usage. At hearing, parties cross-examined SoCalGas's witness who on the stand accepted a small revision proposed by SCGC's attorney.¹⁰

SCGC also objects to SoCalGas process for evaluating bids in which seasonal bids receive fourth priority. SCGC contends that:

"The priority schedule assigning a fourth priority to seasonal bids should be rejected as violative of the CSA requirement that `customer's maximum bidding right shall be determined by a formula that fairly balances seasonal and annual usage.' SoCalGas should award capacity for each month on the basis of the bids for that month without giving priority to annual bids."¹¹

SCGC's concern stems from a belief that "in all likelihood, only bids for capacity on an annual basis will be awarded for preferred receipt points." SCGC did not present an alternative proposal addressing seasonal usage in their testimony.

In its opening brief, Edison proposes a clarification to Schedule G-BR Special Condition 29 to include a reference to "seasonal bids" where the term "monthly bids" appears to clarify that a seasonal bid may extend beyond one month and represent several contiguous months. In its reply, SCGC did not object to Edison's proposal, but emphasized instead that Edison's proposal did not resolve the priority issue SCGC raised in its opening brief.

SCGC's uncontested proposal to delete the word "substantially" from Schedule G-BR in Subsection 2 of Special Condition 29 on Sheet 11 is reasonable as it clarifies the tariff and should be adopted. We will also clarify Special Condition 29 of Schedule G-BR as proposed by Edison and include a reference to seasonal bids. [In the attached tariffs in Appendix B, Special Condition 29 has been renumbered as Special Condition 30.]

We find that SoCalGas fairly balances seasonal and annual usage by permitting both types of customers to participate in the open season. SoCalGas also proposes a reasonable method for evaluating bids during open season. SCGC speculates in its opening brief that seasonal bidders will be harmed because they may not receive capacity, but SCGC has not offered any convincing concrete evidence of the likelihood of such harm. Moreover, SCGC has not offered any alternative tariff sheets for the Commission to consider. In the Scoping Memo issued in this proceeding, the assigned Commissioner placed parties on notice that:

"The issues to be considered in this proceeding are limited to the adoption of tariffs, as proposed in the compliance case of SoCalGas, for implementing D.01-12-018. In the near term, the issues raised in the preferred case of SoCalGas and by other parties at the second meet-and-confer will be considered as part of the informal efforts described above. Intervenor testimony should be limited to responding to SoCalGas' compliance case. Intervenors should also include in their testimony alternate proposed tariff sheets when disputing the tariff sheets proposed by SoCalGas." (Scoping Memo at p. 4. Emphasis added.)

Although SCGC raises some potential problems with SoCalGas' approach, we have no alternative proposal from SCGC to consider and are unwilling to reject SoCalGas' proposed approach on a belief of the "likelihood" of an occurrence. Except for the changes described above, SoCalGas' proposal for seasonal usage customers should be adopted.

f) Disclosure of Terms for Set-Aside
and Open Season Capacity

SoCalGas has not proposed to disclose any information about set-aside or open season capacity. SCGC requests that the Commission direct SoCalGas to disclose information about set-aside capacity and contracts awarded through the open season. SCGC cites no provision in the CSA or D.01-12-018 that explicitly requires the disclosure of such information on SoCalGas' electronic bulletin board. Instead, SCGC makes public policy arguments for why such information should be disclosed.

SCGC's proposal would modify the CSA by imposing new disclosure requirements not contained in the CSA. It would be patently unfair and prejudicial to other parties if we were to consider SCGC's proposal to modify the CSA. SCGC's proposal to require SoCalGas to disclose information about set-aside capacity and contracts awarded through the open season should be rejected as outside the scope of this proceeding.

g) Long-Term Firm Contracts

Section 1.9 of the CSA addresses the effect of the CSA on existing contracts for services by SoCalGas. The CSA does not alter existing contracts with SoCalGas. Section 1.9 in relevant part states:

"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."

Based on the above provision, CCC requests on behalf of three of its members (Oxnard 3) that the Commission make the following findings concerning long-term transportation contracts (Oxnard 3 contracts) approved in D.93-11-021:

· SoCalGas must implement the CSA in a manner that preserves the benefit of the bargain struck in the Oxnard 3 contracts;

· The benefit of the bargain struck in the long-term contracts requires SoCalGas to provide firm-transportation service at a volumetric rate for all of the volumes of gas moved under the Oxnard 3 contracts; and

· To the extent that the Oxnard 3 elect not to use the Oxnard 3 contracts, SoCalGas must allow the Oxnard 3 to exercise the same rights as other SoCalGas noncore customers during the open season.

SoCalGas proposes to implement Section 1.9 of the CSA by doing the following:

· offer set-aside rights at specific receipt points to customers who currently receive firm delivery service through specific receipt points under their long-term contracts;

· offer bidding rights in the open season for firm-backbone rights to customers who currently receive firm delivery service under their long-term contracts; and

· offer interruptible backbone rights to customers who currently receive interruptible delivery service under their long-term contracts.

For Oxnard 3 contracts that currently allow customers to take firm deliveries of gas through the Wheeler Ridge receipt point, SoCalGas proposes to preserve the benefit of the bargain for these customers by offering them set-aside rights at Wheeler Ridge for an amount of capacity equal to their firm contract volumes. We observe from the testimony of CCC that some contract terms terminate but provide for annual renewal options for a specified amount of time. So long as the renewal options continue to confer the right to receive gas at the specific receipt point, SoCalGas' approach is reasonable. SoCalGas should not implement Section 1.9 of the CSA in a manner that confers greater benefits than those bargained for in the contracts subject to Section 1.9 of the CSA.

For contracts that provide parties the option to take service under SoCalGas' tariff rather than under their contracts, SoCalGas proposes to allow such parties to reduce their set-aside rights at Wheeler Ridge so that they can bid the difference in the open season at any receipt point, just like any other customer may use bidding rights at any receipt point. CCC does not protest this approach and we find that SoCalGas' approach is reasonable.

SoCalGas further proposes that the Oxnard 3 customers' total bill under CSA implementation be no higher than under their long-term contracts, regardless of whether these customers obtain backbone rights through set-asides or the open season. SoCalGas will ensure this result through a crediting process. SCGC objects to the crediting system, in section 3.j below. We address this issue separately.

Pursuant to CCC's request, we reaffirm that SoCalGas should implement the CSA in a manner sufficient to prevent Oxnard 3 customers from losing the benefit of the bargain in the Oxnard 3 contracts. The Oxnard 3 contracts have not been subject to examination in this proceeding; consequently we refrain from making specific findings concerning such contracts.

h) Long-Term Interruptible Contracts

SoCalGas believes that different levels of service currently exist on SoCalGas' system. SoCalGas states that although all customers have equal access into SoCalGas' system under the current bundled environment, customers pay for varying levels of certainty, firm and interruptible, for their deliveries of gas. SoCalGas contends that customers who currently pay for and receive interruptible service under their contracts are not entitled under the CSA to a free upgrade to firm backbone rights. SoCalGas also states that customers who currently have only interruptible service could, like any other customer, bid for and pay for firm backbone capacity.

SoCalGas proposes that customers with interruptible long-term contracts should have the opportunity to purchase interruptible backbone capacity to match their needs. SoCalGas proposes to credit all purchases of interruptible backbone capacity against these customers' otherwise-applicable contract bill. Under its proposed treatment, SoCalGas states customers of long-term interruptible contracts would pay no more than they would otherwise pay under their long-term contracts, thus preventing such customers from losing the benefit of the bargain of their long-term contracts.

IP states that the Commission should announce clear principles in its decision upholding the benefit of the bargain for all long-term contracts.

IP does not appear to contest the treatment SoCalGas proposes for interruptible long-term contracts. Nor does IP appear to claim that SoCalGas' proposed treatment for long-term interruptible contracts fails to maintain the benefit of the bargain for interruptible contracts.

We reaffirm the CSA's stated policy that customers should not lose the benefit of the bargain contained in their long-term contracts. Consistent with this policy, SoCalGas has stated that it intends to apply its tariffs in a manner that maintains the benefit of the bargain for interruptible customers. SoCalGas' proposed treatment of holders of interruptible long-term contracts is reasonable and consistent with the CSA.

i) Contract Determination

SoCalGas takes no position as to which of its long-term contracts are firm contracts and which are interruptible contracts. SoCalGas states that no party proffered its contract in this proceeding and opposes using this proceeding to decide the status of contracts. Consequently, SoCalGas objects to CCC's request for a determination that volumes that quality for "Tier 2" rates under the Oxnard 3 contracts are firm and should be treated like "Tier 1" volumes (for which the Oxnard 3 will receive set-asides and/or bidding rights). SoCalGas believes the request is inappropriate since CCC did not place the terms of its Tier 2 volumes at issue in this proceeding.

Similarly, SoCalGas objects to the extensive argument in the IP opening brief addressing the question of whether enhanced oil recovery (EOR) contracts are firm. SoCalGas supports the request of IP to establish a Commission forum for expeditiously reviewing long-term contracts to determine whether the holder of the contract qualifies for interruptible or firm service.

IP is concerned that the record is unclear concerning the criteria that SoCalGas uses to distinguish between "firm" and "interruptible" long-term contracts. IP asserts that that the ALJ sustained an objection by SoCalGas' counsel that precluded the Indicated Producers from exploring the basis for how SoCalGas differentiates between firm and interruptible long-term contracts.

IP also provides a "guess" at SoCalGas' rationale for distinguishing between firm and interruptible contracts and further provides a discussion aimed at disproving its "guess" of SoCalGas' rationale. Lastly, IP requests that the Commission provide a forum for expedited resolution of contract interpretation disputes to ensure that all customers are prepared to participate in any upcoming open seasons for backbone transmission receipt point rights.

IP appears to argue that no basis exists to distinguish between long-term contracts. IP also appears to claim that it was denied a fair opportunity at hearing to explore through cross-examination the basis for SoCalGas distinction between "firm" and "interruptible" long-term contracts.

We are sympathetic to IP's desire for swift resolution concerning its dispute with SoCalGas about the classification of its contracts. However, this proceeding was intended as a proceeding to implement D.01-12-018 by adopting tariffs. This proceeding was not intended to resolve contract specific issues. At hearing, the ALJ provided ample opportunity to IP to explore how firm versus interruptible contracts would be treated.

We also support in principle, IP's proposal for the Commission to establish a forum for expedited review and resolution of disputes concerning whether a long-term contract is firm or interruptible. We invite IP and SoCalGas to submit to the Commission proposals for informal or formal resolutions of their contract disputes.

j) Credit Payments for Backbone
Capacity

As discussed above, SoCalGas proposes to offer bidding rights in the open season to customers that currently have long-term contracts for firm delivery service. The granting of bidding rights will enable these customers to obtain firm backbone transmission rights. SoCalGas proposes to credit payments for backbone capacity against monthly bills for discount long-term contracts to ensure that these customers pay no more for their new backbone capacity than they otherwise would have paid for similar service under their long-term contracts.

If a customer is receiving gas transportation service at a discounted rate under a long-term contract, SoCalGas currently records the shortfall in its Noncore Fixed Cost Account (NFCA). SCGC alleges that SoCalGas' proposed credit would exacerbate the shortfall that is recorded in the NFCA. The basis for SCGC concern is a hypothetical question posed to SoCalGas' witness that would result in SoCalGas crediting a customer for two units of service (based on two units of backbone capacity being reserved) when in fact the customer only used one unit of service (50% load). In its reply brief, DGS also echoes the concern raised by SCGC.

In its reply brief, SoCalGas states that SCGC's hypothetical is flawed because SCGC wrongly assumes that SoCalGas would credit the hypothetical customer for two units of reserved backbone capacity when the hypothetical customer only consumed one unit of capacity.

We agree with SoCalGas that SCGC's hypothetical improperly provides the customer with more benefit due under the customer's long-term contract. SCGC has not demonstrated how SoCalGas' proposal to credit payments for backbone capacity against monthly bills for discounted long-term contracts prejudices ratepayers or exacerbates shortfalls recorded in the NFCA. Based on its representation that its crediting approach will not exacerbate existing NFCA shortfalls, SoCalGas' proposal to credit payments for backbone capacity against monthly bills for discounted long-term contracts is reasonable.

4. Tariff Schedule G-IMB, Rule 23 and Rule 40

a) 2.44% In-Kind Fuel Charge

SoCalGas' proposed Schedule G-IMB and Rule No. 40 together describe the terms and conditions under which SoCalGas will provide imbalance services for customers when their usage differs from their transportation deliveries to SoCalGas' local transmission system. Under Tariff Schedule G-IMB, SoCalGas will calculate and inform customers of imbalances, provide opportunities to avoid and minimize imbalances, and charge for or cash out imbalances exceeding tolerances.

In Tariff Schedule G-IMB at Sheet 2 under the heading "In-Kind Fuel Charge," SoCalGas proposes to levy a charge on the net increase on noncore customer's imbalances as follows:

"An in-kind fuel charge shall be levied on the net increase (if any) in every noncore customer's imbalance account after each monthly imbalance trading period relative to the previous monthly trading period. This charge shall be applicable only during months with net overall system injection.

In-kind fuel charge for a positive imbalance........2.44%"

In Rule 40 at Sheet 1, the tariff states that:

"For providing the default noncore balancing service, an in-kind fuel charge of 2.44% shall be levied on the gas remaining in a noncore customer's imbalance account immediately after each monthly imbalance trading period."

SoCalGas believes the 2.44% in-kind fuel charge for balancing services reflects the costs that customers cause SoCalGas to incur when they use balancing services. Specifically, SoCalGas states that the charge reflects the "actual variable cost incurred at the storage compressor stations as they inject gas into the storage fields to accommodate positive imbalances for balancing customers as those injection requirements are incurred." SoCalGas asserts that the proposed charge properly assigns actual costs to the customers who cause them. SoCalGas also contends that such an approach to assigning costs is consistent with various provisions in the CSA that separately state the costs that are associated with specific services. Moreover, SoCalGas believes its approach will send accurate price signals to customers.

SoCalGas also argues that D.01-12-018 supports SoCalGas' interpretation the CSA. The relevant part of D.01-12-018 that SoCalGas relies on is a statement that:

Section 3.2.3.3 of the CS states that the costs 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. We agree that it is appropriate to remove the costs of default balancing from the costs of other unbundled services, but we are concerned that bundling these costs with the transportation rate for local transmission and distribution will cause the core to pay for some portion of the costs of default noncore balancing. We therefore direct SoCalGas to present a detailed description of how they will ensure that the costs of noncore default balancing will be allocated only to those noncore customers using default balancing services in the advice letter(s) filed to implement this order. (D.01-12-018, mimeo., p. 66, emphasis added.)

Consequently, SoCalGas argues that with respect to the storage injection costs incurred to provide default balancing service, SoCalGas' proposed 2.44% in-kind fuel balancing charge complies with the statement in D.01-12-018 to "ensure that the costs of noncore default balancing will be allocated only to those noncore customers using default balancing services." SoCalGas argues that the Commission should "unbundle the variable fuel costs associated with storage injections necessary to provide default balancing service from the bundled local transportation/distribution rate in accordance with D.01-12-018."

IP opposes the imposition of an in-kind fuel charge for transportation services because the proposed charge could result in significant costs for customers. IP argues that the Commission should reject SoCalGas' proposal for an in-kind fuel charge for transportation services since the charge was not part of the bargain reached in the CSA or adopted by D.01-12-018.

IP also contends that SoCalGas late in the process unilaterally added to its tariffs the in-kind fuel charge. IP argues that the in-kind fuel charge first appeared in AL 3146 on May 1, 2002. IP observes that after the Commission issued D.01-12-018 SoCalGas held a series of workshops for interested parties and customers to discuss implementation of D.01-12-018. At evidentiary hearing, IP introduced Exhibit 3 which represented handouts entitled "Gas Industry Strategy Implementation Meeting" distributed by SoCalGas at a presentation it made on January 9, 2002. The handouts reference "Default Balancing (Revised Rules)" and IP contends that the handout shows that default balancing did not change in comparison to current procedures, noted as "+/- 10% monthly and OFO daily tolerances." IP also observes that at a subsequent workshop held on April 11, 2002, SoCalGas also discussed balancing rules and circulated proposed tariffs that purported to incorporate the major changes required by the CSA and D.01-12-018. Exhibit 4, which IP sponsored, contains the proposed tariff G-IMB and Rule 40 that SoCalGas circulated at the April 11 workshop. Neither tariff contained a reference to an in-kind fuel charge.

IP also rejects SoCalGas' argument that Section 2.1.3.2 of the CSA authorizes SoCalGas to impose an in-kind fuel charge for all balancing services. IP argues that Section 2.1.3.2 applies only to storage services.

Coral also opposes SoCalGas' proposal to impose a 2.44% in-kind fuel charge. In describing how the CSA addressed balancing, Coral asserts that Section 3.2.3 CSA established a "self-balancing option." Further, Coral contends that customers that decline the self-balancing option will receive, pursuant Section 3.2.3.1 of the CSA, the same default balancing service that is provided today. Coral cites Section 3.2.3.1 of the CSA for the proposition that:

"[t]he 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
. . . ." (Emphasis added.)

Coral states that under "default balancing" that is provided today, a customer's usage that stays within 10% of its scheduled gas deliveries over the course of a month avoids separate balancing charges. Coral states that SoCalGas' current G-IMB tariff provides as follows:

"Balancing Service will be provided without charge if the cumulative imbalance at the end of the monthly imbalance trading period is within 10 percent of the customer's usage (Tolerance Band) for the billing period" (emphasis added).

Consequently, Coral reasons that SoCalGas' proposal for "default" noncore monthly balancing of an in-kind 2.44% fuel charge has no basis in the CSA.

Coral also rejects SoCalGas argument that the 2.44% in-kind fuel charge is analogous to other provisions of the CSA. Coral asserts that in the absence of an express provision of the CSA, the Commission should reject SoCalGas' efforts to introduce a change to the CSA thought its compliance tariffs. DGS also argues that the in-kind 2.44% fuel charge has no basis in the CSA.

We are persuaded by IP and Coral that SoCalGas' proposed 2.44% in-kind fuel charge for balancing is inappropriate. SoCalGas cites no express provision to support the imposition of such a charge. We reject SoCalGas' interpretation that Section 3.2.3.3 of the CSA authorizes such a charge since this provision of the CSA deals with storage services and not balancing. Moreover, SoCalGas' interpretation would create an inconsistency with Section 3.2.3.1 which expressly states that the cost of default balancing will not be adversely affected. Since existing default balancing service is provided without charge (if the cumulative imbalance at the end of the monthly imbalance trading period is within 10%), we are unable to endorse SoCalGas' interpretation that Section 3.2.3.3 of the CSA authorizes a 2.44% in-kind fuel charge for balancing. IP and Coral have both shown that imposition of a 2.44% in-kind fuel charge for balancing may adversely affect the cost of default balancing.

In addition, since the CSA is silent concerning the imposition of a 2.44% in-kind fuel charge for balancing we may look to the parties conduct to determine whether the signatories to the CSA intended that a 2.44% in-kind fuel charge be imposed for balancing. As evidenced by SoCalGas' own documents and proposed tariffs in discussions with other parties immediately following the issuance of D.01-12-018, SoCalGas was silent concerning the imposition of a 2.44% in-kind fuel charge for balancing. The conduct of SoCalGas subsequent to the adoption of the CSA reflected an intent consistent with IP and Coral's position that the CSA did not authorize a 2.44% in-kind fuel charge for balancing.

Although, SoCalGas has offered some colorable argument about cost allocation in this proceeding for why a 2.44% in-kind fuel charge for balancing should be imposed, the purpose of this proceeding is not to adjudicate the CSA issues a second time, but to implement the terms of the CSA. Consequently, we give little weight to SoCalGas' costs allocation argument.

IP has demonstrated that SoCalGas' conduct subsequent to the adoption of the CSA reflected an intent consistent with IP and Coral's position that the CSA did not authorize a 2.44% in-kind fuel charge for balancing. Although, SoCalGas has offered valid argument in this proceeding for why such a charge should be imposed, the purpose of this proceeding is not to adjudicate the issue a second time, but to implement the terms of the CSA. As evidenced by SoCalGas' own documents and proposed tariffs in discussions with other parties after the CSA was implemented, SoCalGas manifested an intent consistent with the positions of IP and Coral that the CSA did not authorize 2.44% in-kind fuel charge for balancing.

We are also persuaded by Coral's analysis that neither the CSA nor D.01-12-018 authorizes SoCalGas to impose a 2.44% in-kind fuel charge for balancing. We agree with Coral that the cost of default balancing should not be adversely affected by the CSA. Since existing default balancing service is provided without charge (if the cumulative imbalance at the end of the monthly imbalance trading period is within 10%), we are unable to endorse the proposal of SoCalGas to impose a 2.44% in-kind fuel charge for balancing.

b) Involuntary Diversion of Noncore
Supplies

In the event service is threatened for core customers, SoCalGas proposes in Rule 23 to divert noncore supplies for the benefit of core customers. Proposed Rule 23 states in relevant part:

"In the event insufficient gas supply or capacity is available on its backbone transmission system for the Utility to meet the requirements of its core customers, the Utility may effectuate involuntary diversions of supply originally intended for the Utility's noncore customers."

Rule 23 also provides compensation, in the form of an involuntary diversion credit, for affected noncore customers in an amount equal to $25 per decatherm when noncore supplies are diverted.

In response to criticisms that its tariffs should define the precise circumstances under which SoCalGas will divert supply and the precise actions that it will take to avoid a diversion, SoCalGas asserts that it needs the ability to exercise discretion when faced with specific facts and circumstances. SoCalGas also states that it has refined Rule 23 to take all reasonable steps to avoid a diversion. Specifically, SoCalGas has modified Rule 23 to call a Stage 2 OFO and eliminate all IT storage withdrawals before diverting noncore supplies. Additionally, SoCalGas Gas states that its gas acquisition department is willing to: (1) use all of its own firm backbone capacity to the extent gas is available; (2) use any interruptible backbone capacity at any receipt point to the extent gas is available; and (3) use all other reasonable market opportunities, including buying gas.

Coral contends that an involuntary supply diversion constitutes a draconian measure that represents an expropriation of gas and transportation that belongs to noncore customers. Coral believes that SoCalGas should only divert noncore supplies when severe "operational" conditions prevent SoCalGas from purchasing and transporting gas supplies for its core customers.

Even though Rule 23 provides that the gas acquisition department of SoCalGas will use all other reasonable market opportunities, including buying gas, Coral is concerned that SoCalGas may impose an involuntary supply diversion at a time when SoCalGas' gas acquisition department is otherwise able to purchase gas supplies from other sources. While Coral supports the language contained in Rule 23, Coral does not support an interpretation that may allow for an involuntary supply diversion for economic reasons, i.e. in order to "avoid the purchase of relatively more expensive core gas supplies." To the extent the tariffs must be amended to provide this clarification, Coral urges the Commission to amend Rule 23.

SCGC echoes many of the same concerns raised by Coral. In addition, SCGC requests that the Commission strike the word "reasonable" from the following language in Rule 23:

"Use all reasonable market opportunities, including buying on the open market to alleviate the problem."

SCGC asserts that elimination of the word "reasonable" will require SoCalGas to buy gas on the open market to alleviate a problem that may otherwise give rise to an involuntary diversion of noncore gas.

In its reply brief, Indicated Producers expresses support for Coral's position in its opening brief and argues that the use of the word reasonable in Rule 23 leaves open the possibility that SoCalGas may divert noncore supply rather than purchase gas on the open market.

We believe that the issue raised is whether SoCalGas must always purchase supply on the open market to alleviate problems that may lead to an involuntary supply diversion.

Section 1.5.4 of the CSA clearly envisioned the possibility that involuntary supply diversions might occur. Section 1.5.4 of the CSA states in relevant part that:

"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."

In response to concerns raised by Coral and others to a previous version of Rule 23, SoCalGas took steps to modify Rule 23 to alleviate such concerns by indicating in Rule 23 specific steps that SoCalGas would take to alleviate problems that may lead to an involuntary supply diversion. In fact, Coral states that it supports the language of Rule 23 but it seeks a clarification that SoCalGas will always buy supply in the open market prior to instituting an involuntary supply diversion.

We agree in principle with Coral, SCGC and Indicated Producers that diversions should not occur for solely economic reasons. However, we also agree with SoCalGas that it is difficult to envision every situation in which an involuntary supply diversion may occur.

SoCalGas' proposed Rule 23 implements Section 1.5.4 in a manner that strikes a reasonable balance between parties' concerns and SoCalGas' ability to operate its system. SoCalGas' Proposed Rule 23 responds to parties concerns by setting forth reasonable steps that SoCalGas will take prior to resorting to an involuntary supply diversion of non-core gas. At hearing concerning problems that may lead to a diversion, SoCalGas stated that it will use all "reasonable market opportunities, including buying on the open market to alleviate the problem." We are reluctant, and find it unreasonable, to limit the options available to SoCalGas concerning unknown situations. Consequently, we find that SoCalGas' proposed language in Rule 23 for imposing involuntary diversions of noncore gas supplies is reasonable and should be adopted.

c) Involuntary Supply Diversion and
Backbone Reservation Charges

In the event of an involuntary supply diversion, SoCalGas proposes to limit its cost responsibility to an involuntary diversion credit (IDC). Proposed Rule 23(E) provides that:

"[i]n the event the Utility diverts gas supply, the Utility shall not be responsible for any interstate or intrastate pipeline transmission charges associated with diverted gas. The Utility's total cost responsibility for the diverted gas supply shall be equal to the Involuntary Diversion Credit times the volume of gas diverted."

Coral contends that in the event of an involuntary supply diversion, SoCalGas should relieve a backbone shipper of its backbone reservation charges for the duration of the diversion event. In support of its position, Coral makes several arguments. It contends that an involuntary supply diversion is a force majeure event that relieves shippers of their duty to pay backbone reservations charges. Coral also argues that the $25.00 per dth IDC may not fully compensate a customer that incurs a diversion. Lastly, Coral believes that SoCalGas should not require a customer to pay backbone reservation charges since a customer that is subject to a supply diversion is denied the right to use its firm receipt point capacity.

In response to Coral, SoCalGas states that the IDC is the exclusive means identified in the CSA for compensating noncore customers whose supplies have been diverted. SoCalGas states that Coral provides no reference to the CSA for its proposed waiver of the reservation charges. SoCalGas believes that Coral is trying to impose a new requirement not contained in the CSA and that the Commission should reject such an attempt to modify the CSA.

The issue raised by Coral is whether a noncore customer's duty to pay backbone reservation charges is suspended during a diversion event. We believe the answer is no. Coral's arguments assume that this is a matter of first impression. However, the CSA at Section 1.5.4 acknowledges that "operational conditions" may exist that require the diversion of supply. Further, the CSA provides that customers subject to a diversion will be compensated $25/dth. The CSA is straightforward in describing the consequences that follow "operational conditions" that threaten end-users. The signatories to the CSA, including Coral, agreed that:

"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 involuntary 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." (CSA Section 1.5.4.)

Pursuant to the CSA, Coral as signatory agreed to be subject to a involuntary supply diversion and to receive the compensation set forth in the CSA. We agree with SoCalGas that no provision exists that relieves customers of the backbone reservation charges. Signatories to the CSA agreed to a $25/dth credit in compensation, regardless of the actual cost to the customer. Section 1.5 of the Settlement Agreement states that it is a "negotiated compromise" and that the:

"Settlement Agreement is to be treated as a complete package and not as a collection of separate agreements on discrete issues or proceedings."

Coral's proposal to suspend the payment of backbone reservation charges during a supply diversion event should be rejected.

d) Involuntary Diversion Credit and
Force Majeure

SoCalGas proposes that:

"The Involuntary Diversion Credit does not apply when the diversion is the result of Force Majeure. However the Involuntary Diversion Credit will apply for a diversion resulting from high demand due to weather conditions." (Rule 23.E at Sheet 6.)

Coral opposes SoCalGas' proposal. Coral argues that SoCalGas has not demonstrated why it should not have to pay an IDC in a force majeure situation. Coral contends that involuntary supply diversion is most likely to occur in a force majeure situation. The parties to the CSA did not agree to excuse SoCalGas from providing an involuntary diversion credit when a force majeure event occurs.

Coral cites Section 1.5.4 of the CSA, for the proposition that a supply diversion will only occur when "operational conditions" prevent SoCalGas from serving its core customers. Coral argues that "operational conditions" include gas supply, pipeline and storage conditions that can arise as a result of force majeure. Coral contends that to deny a diversion credit under these circumstances would diminish the value of the credit, and would diminish the value of firm receipt point capacity rights.

SCGC also argues that IDC should apply when involuntary supply diversions are caused by force majeure events. SCGC argues that SoCalGas proposal is unsupported by the CSA. SCGS believes that Section 1.5.4 of the CSA provides that if a noncore customer's gas supply is involuntarily diverted to prevent curtailment of core customers, a $25/dth diversion charge will be assessed to core customers. The revenues derived from assessing the diversion charge will be credited to the noncore customers who had their gas diverted. SCGC argues that there are no exceptions. SCGC believes that the diversion charge should be assessed against core customers whenever gas is involuntarily diverted from noncore customers for their benefit, and the diversion credit will be given to noncore customers whenever their gas is involuntarily diverted.

SCGC argues that the exception for force majeure events represents a substantial departure from the diversion credit provision of the CSA. SCGC agrees with Coral that creating an exception for force majeure would render the IDC largely worthless.

SCGC also dismisses SoCalGas' claim that the IDC should not apply during force majeure situations because it is "common industry practice" not to give credits in force majeure situations. SCGC disputes SoCalGas' argument as untrue and cites a recent Federal Energy Regulatory Commission (FERC) action requiring El Paso Natural Gas Company (El Paso) to give partial demand charge credits for force majeure events.¹² SCGC concludes that the IDC should be given to customers that have their gas diverted, as contemplated by the CSA.

Although SoCalGas believes that its proposal is reasonable and consistent with industry practices, it has agreed to withdraw its proposed IDC exemption for force majeure events in response to concerns raised by parties.

We will accept SoCalGas' proposed change and modify SoCalGas proposed Rule 23 to eliminate the IDC exemption for force majeure events.

e) Notification to End-Use Customers of
an Imminent Supply Diversion

In response to concerns raised by Coral and others, SoCalGas has agreed to make best efforts to notify balancing entities and end-use customers, through its electronic bulletin board and through other means, of an involuntary supply diversion.

Coral believes that the Commission should modify SoCalGas' proposed tariffs so that SoCalGas faces economic penalties if it fails to provide notice to all balancing entities, and all noncore end-use customers of an involuntary supply diversion. In support of its position, Coral appears to make an equity argument. Coral states in its opening brief that since under the CSA balancing entities face charges if they fail to comply with a supply diversion, SoCalGas also must face charges if it fails to provide notice.

Coral requests that the Commission modify Rule 23(E) to impose an affirmative responsibility on SoCalGas to notify all balancing entities, and all noncore end-use customers, of any involuntary supply diversion. Further, that prompt notification must be a precondition for the imposition of any charge for the unauthorized use of involuntarily diverted supply. Coral argues that unless this provision is adopted, SoCalGas will bear no actual responsibility for notifying its customers of a supply diversion.

In reviewing Coral's concern, we are not convinced that the CSA imposes a duty upon SoCalGas to notify end-users of an imminent supply diversion. Moreover, Coral cites no provision in the CSA that imposes a financial charge on SoCalGas if it does not notify an end-use customer of a supply diversion. At hearing, SoCalGas' witnesses Schwecke and Watson also pointed out that balancing entities are in a better position than SoCalGas to know when their customers' supplies are being diverted and that it is the balancing entities that are responsible for meeting the demands of end-use customers on a daily basis regardless of whether a diversion is occurring. Absent some specific authority in the CSA, we refuse to impose new conditions upon SoCalGas via its tariffs in this proceeding.

5. SoCalGas' November 24, 2003 Motion to
Strike

In its opening brief, PG&E alleged that SoCalGas' proposed Schedule G-BR is unduly discriminatory because it does not treat all pipleline interconnections equally. PG&E states that Schedule G-BR excludes the Kramer Junction interconnect as a secondary receipt point for the North Needles receipt point and North Needles (expansion) Receipt Point. Further, PG&E argues that no lawful or rational basis exists for this treatment and that such treatment would result in undue discrimination against gas supplies from the Kern River Pipeline into SoCalGas' system as compared to gas flowing from other pipelines in the Southwest. PG&E believes that the issue of whether Kramer Junction should be made a secondary receipt point is within the scope of this proceeding since SoCalGas inserted Kramer Junction into its Schedule G-BR as a primary right receipt point.

PG&E also requests in its opening brief that the Commission amend schedule G-BR to clarify that interruptible or secondary firm nominations on the SoCalGas system will be scheduled up to the maximum operating capacity available each day, at each receipt point.

On November 24, 2003, SoCalGas filed a motion to strike the opening brief of PG&E on the basis that the brief addresses issues that are outside the scope of this proceeding. SoCalGas states that PG&E's opening brief proposes to aggregate receipt points in a manner not authorized either by the CSA or D.01-10-018. SoCalGas also complains that PG&E's approach of raising new issues in its opening brief denies other parties a fair opportunity to address PG&E's proposal in rebuttal testimony.

We agree with SoCalGas ` criticism of PG&E's tactic of raising a factual issue and presenting a new proposal in its opening brief. Although counsel for PG&E was present at evidentiary hearing, PG&E did not conduct any cross-examination or present testimony in support of its modification. PG&E alleges discrimination, but without a factual record concerning the circumstances surrounding SoCalGas' proposed treatment for Kramer Junction, we have no basis for finding that a discriminatory situation exists. It would be grossly unfair to other parties to consider PG&E's proposed modification without a factual record or an opportunity for other parties to respond with rebuttal testimony. Consequently, PG&E's proposal should be denied. Since we have addressed PG&E's proposal we will deny the motion of SoCalGas to strike PG&E's opening brief.

6. Petition to Modify

On October 23, 2003, SCGC, IP, Coral, Cabrillo I, LLC, Cabrillo II, LLC, El Segundo Power, LLC, Long Beach Generation, LLC, DGS, and TURN (Joint Parties) filed a petition to modify D.01-12-018 (petition). The petition requests that the Commission vacate D.01-12-018 and Resolution G-3334. Further, the Joint Parties request that the Commission solicit input on new policy objectives and direct SoCalGas to file a new application by January 1, 2005, proposing a regulatory framework that reflects the current and anticipated market conditions. In the interim, Joint Parties state that SoCalGas should continue to provide service under existing tariffs.

Joint parties contend that circumstances in the Southern California Market have changed since the execution of the CSA and that the CSA is no longer directly responsive to the circumstances existing on the SoCalGas system. Joint Parties petition is broken down into three parts: (1) key issues that the CSA sought to address but have already been addressed; (2) changes that have altered the envisioned use of receipt point capacity; and (3) effects of price volatility in the market. Based on these changes, Joint Parties conclude that the Commission has a legal duty to vacate D.01-12-018 because its implementation would not be in the public interest.

a) Key Issues Have Been Addressed

Joint Parties believe that the D.01-12-018 should be vacated because certain issues that the CSA sought to address have been resolved. In particular, Joint Parties state that the allocation of capacity on the El Paso Natural Gas Company (EPNG) system has changed. Joint Parties state the FERC has ordered EPNG to convert from full requirement contracts to contract demand contracts effective September 1, 2003. Joint Parties conclude that these "reforms" to the EPNG system have diminished the need for the receipt point capacity provisions of the CSA. Joint Parties also state that SoCalGas system expansions have added flexibility to the system. Joint Parties also believe that SoCalGas actions to eliminate "windowing" - a process that restricted shipper nomination on the SoCalGas system - and the institution of new procedures have improved the operation of SoCalGas' system. Some members of Joint Parties assert that elimination of windowing may have eliminated the need for a system of firm tradeable receipt point rights while other members believe that elimination of windowing should delay the implementation of firm tradeable receipt point rights for further consideration.

Watson opposes the petition and asserts that the passage of time has not changed the benefits of the CSA. Watson criticizes the petition for citing changes but then not making a serious attempt to explain whether these changes undermine the expected benefits of the CSA. Watson states that while capacity allocation on the EPNG system may be operating more smoothly there is no guarantee that the system will continue to do so in the future. Watson also believes that it is important for the Commission to retain and exercise control over the energy delivery system that it has jurisdiction over rather than rely on FERC to do the right thing during a crisis.

Watson also asserts that system expansions will benefit California consumers just as much, if not more, under the CSA than under today's regulatory structure. Watson observes that under the CSA, SoCalGas will have the incentive to sell the new capacity to the market and the incentive to maximize sales because SoCalGas is at 100% risk for recovery.

b) Changes that Affect the Envisioned
Use of Receipt Point Capacity

Joint Parties believe that D.01-12-018 should be vacated because changes in intrastate delivery capabilities and core upstream commitments have and will continue to alter the use of receipt point capacity as envisioned by the CSA. Specifically, Joint Parties state that upstream pipelines have expanded capacity to serve California and thus the need for capacity at various receipt points has changed. Joint Parties assert that allocation of receipt point capacity rights will change as the upstream capacity rights expand and such changes alter the assumptions made about the value of receipt point rights. Joint Parties believe the Commission should consider these changes in developing a regulatory structure for the SoCalGas system. Joint Parties also believe that "potential liquefied natural gas (LNG) projects, if built" will alter the need and use of receipt point capacity. Joint Parties also believe that the core class must receive a set-aside for the North Coastal set-aside that was displaced by the ExxonMobil set-aside.

In response to the Joint Petition, SoCalGas supports vacating D.01-12-018 because subsequent to the adoption of the CSA, the Commission has adopted polices in favor of increasing conservation whereas the CSA encourages SoCalGas to maximize throughput on its system. SoCalGas also believes the interchangeability of receipt point access rights should be allowed to accommodate new gas supplies on a non-discriminatory basis.

In response to the Joint Petition, Marathon Oil Company (Marathon) seeks resolution of this proceeding so that the consolidated BCAP proceedings can proceed and address the issue of providing firm tradeable rights for re-gasified LNG.

Watson states that the expansion of upstream capacity actually highlights the benefits of the CSA. Under the CSA, Watson asserts that customers can indicate the value they place on receipt point rights by the bids they place in the open season and subsequent transactions in the secondary market. Watson believes that the CSA in fact considers the value customers place on receipt points and enhances customers' ability to acquire exactly the set of receipt points they value most in response to whatever is happening on the upstream interstate pipelines.

Watson acknowledges the need to accommodate LNG as a potential new source of gas. However, Watson argues that it is unlikely that any announced LNG project will be online prior to 2006 or 2007 at the earliest. Thus, sufficient time exists to implement the CSA and to also explore modifications to accommodate LNG projects that will become operational in the future. Watson argues that the Commission should implement the CSA and gain several years of valuable experience prior to modifying the CSA to accommodate LNG supplies.

c) Price Volatility

Joint Parties believe that the D.01-12-018 should be vacated because "material changes in tariffs and rules bring a period of transition and uncertainty." Joint Parties assert that natural gas price volatility combined with gas demand volatility creates significant risks for California ratepayers and the change the CSA would introduce would increase market risks for customers. Consequently, Joint Parties believe the most prudent course of action is to defer material changes to the existing regulatory framework.

Watson states that the CSA applies only to the intrastate transportation of gas and thus is largely independent of factors that cause volatility. Based on data from the PG&E system, Watson disputes the assertion that implementation of the CSA will add volatility in the delivered cost of gas for California consumers. Rather, Watson asserts that the CSA may in a modest way moderate volatility in delivered gas prices for gas bought at the border because the CSA allows customers to purchase backbone capacity on the SoCalGas system at cost-based rate that is fixed through August 2006.

Lastly, Watson contends that the Commission should look to the success of the Gas Accord structure on the PG&E system as evidence of the benefits of the CSA. Watson states the CSA in many ways is modeled after the Gas Accord which has worked well under "stress tested" conditions in a range of markets. Additionally, Watson criticizes the petition for aiming to perpetuate the current uncertainty concerning the natural gas market structure for SoCalGas.

d) Discussion

An allegation of "change" or "changed circumstance" in the regulatory market place alone does not constitute sufficient grounds to vacate a Commission decision. The regulatory and market landscape is constantly changing and the Commission would suffer paralysis if it were bound to constantly reconsider every decision it made. However, an assertion of "change" or "changed circumstances" together with a meaningful explanation of how such changes would detrimentally affect the public may constitute grounds for vacating a Commission decision.

In the petition before us, Joint Parties claim an occurrence of "changed circumstances" but provide no meaningful discussion of how such changed circumstances detrimentally affect the public. Instead, Joint Parties merely speculate about detrimental consequences. We agree with Watson that the petition lacks meaningful explanation of how the changes cited would justify abandoning the CSA and vacating D.01-12-018.

Moreover, in response to the changes alleged by Joint Parties to have undermined the CSA's benefits, Watson has convincingly argued that the CSA will bring increased benefit to California consumers. For instance, with regards to the expansion of upstream capacity, Watson demonstrates the benefits of an open season and secondary market by allowing customers to indicate the value they place on receipt point rights by the bids they place in the open season and subsequent transactions in the secondary market. Contrary to Joint Parties' position, the CSA, in fact appears to anticipate some of the changes cited by Joint Parties.

In this instance, Joint Parties' speculation about detrimental consequences does not constitute sufficient grounds to vacate a decision adopted by the majority of the Commission. Nonetheless, the arguments of Watson concerning the benefits of implementing the CSA are much more persuasive than the arguments put forth by Joint Parties and others concerning detrimental impacts of implementing the CSA. The petition to vacate D.01-12-018 of Joint Parties should be denied.

For months the customer uses substantially more than their average base load, customer's monthly maximum bidding rights will be set equal to their historical usage in those particular months during the specified period.