7. Supply Access

At the outset of this LNG discussion, we point out that we are not deciding in this proceeding whether certain proposed LNG projects should be built in California, or on the West Coast. The issue of whether individual LNG projects should be built in California, in Federal waters offshore of California, or in Mexico, is or will be addressed in the applicable regulatory proceedings examining each individual project.

The OIR directed each of the Respondents, except for Southwest, to submit a proposal concerning guidelines for how natural gas supplies from LNG facilities can access each of their intrastate pipelines and distribution facilities to the extent that LNG terminals are constructed on the West Coast. The OIR also directed the Respondents to discuss the costs and terms for interconnecting to these facilities, and to discuss whether any other issues (e.g., bypass or peaking rate issues) exist and how they should be resolved if a shipper receives regasified LNG.

Due to proposed LNG projects located in Baja California, Mexico, SoCalGas and SDG&E were asked to address the following issues concerning access through Otay Mesa, the shortest route connecting Baja LNG projects to southern California: the reasonable amount of expansion capacity (which shippers may be interested in utilizing) and the costs for such capacity expansion for interconnecting facilities and intrastate pipelines to facilitate this gas supply being made available to California; the costs and terms for users of these interconnecting facilities; whether there would be double receipt points (i.e., SDG&E and SoCalGas) or one integrated path for such supplies; and whether any other issues (e.g., bypass or peaking rate issues) exist and how they should be resolved if an entity supplies natural gas through this route or a shipper receives natural gas through this route.

SoCalGas was also directed to propose a means for providing additional access so that Rocky Mountain gas supplies can reach California through SoCalGas' interconnecting facilities. The Respondents were also directed to address any interconnection facility issues that they believe the Commission must decide by the summer of 2004.

The responses of PG&E, SoCalGas and SDG&E are summarized below, and are followed by discussions of the issues raised in the comments.

7.1. PG&E Proposal

7.1.1. LNG Access

PG&E is primarily interested in the development of LNG facilities as a buyer of gas and as a transporter and distributor of gas. As a buyer of gas, PG&E states that LNG holds the promise of an additional supply source, which will moderate prices and create additional opportunities to enhance the diversity of supply. PG&E indicates that its core customers are likely to benefit from LNG either through the contracting for supplies, or from the freeing up of gas supplies that are displaced by LNG in other markets.

PG&E's proposal describes three LNG access scenarios: (1) connecting to Calpine's proposed LNG facility near Eureka;¹³ (2) through the North Baja Pipeline to Ehrenberg then to PG&E; and (3) by SoCalGas allowing nominations from a Los Angeles city gate delivery point to an off-system connection with PG&E.

PG&E states that, as a transporter of gas, it is ready to apply to the Commission for the necessary approvals to connect to any LNG facility, subject to certain proposed principles described below. PG&E states it will build the facilities necessary to transport the gas from the LNG facility (or another utility's pipeline facilities interconnected to the LNG facility) to PG&E's existing gas transmission and distribution network. PG&E states that the planning of these facilities will help ensure that the use of existing facilities are maximized.

PG&E also takes the position that because the new facilities will be built to provide additional supply assurances for PG&E's customers pursuant to Commission goals, the Commission's approval must allow these new facility costs to be fully recoverable and included in rates. According to PG&E, similar assurances were provided in D.02-07-037 where the Commission stated that new interstate pipeline capacity acquired on the El Paso system in compliance with the decision would be found reasonable and recoverable in rates.

PG&E's proposed policy on building Commission authorized connections to new LNG facilities differs from PG&E's current interconnection policy, which requires interstate pipelines and third-party storage providers to build their own facilities to PG&E's system and pay PG&E for its costs to build the interconnect and to make nomination system changes. PG&E believes that such a policy change is warranted if the Commission wants to encourage the siting of LNG facilities in or near California.

PG&E proposes that the approval process for each LNG connection and associated PG&E downstream facilities should allow for a dialogue among interested parties on the needed facilities, costs, economic feasibility, demand for the project, potential changes in the utilization of existing pipeline facilities, rate impacts, and gas quality interchangeability issues. If the Commission decides that an LNG project fails to provide benefits sufficient to outweigh the financial risks, PG&E would not build the connecting pipeline. In such a case, in order for the project to go forward, the LNG facility developer would need to build its own facilities or else pay PG&E to construct the necessary facilities to the nearest interconnect point on the existing transmission system. PG&E does not suggest that the Commission assert authority over whether the LNG project should be built, but states that the Commission does have authority over whether a California jurisdictional utility's gas transmission assets should be built and included in rates.

It is PG&E's position that, since the purpose of the proceeding is to provide assurance that California gas users will continue to have reliable, competitively priced gas supplies, the utilities should not be penalized if some pipeline facilities are not fully utilized because of a substantial change in flow patterns on the system after LNG facilities are built. If throughput on an existing pipeline goes down as a result of new supplies coming from another source at a different point on the system, PG&E proposes that its rates be adjusted so it continues to fully recover the cost of the existing facilities.

PG&E states that the utility should work cooperatively with the LNG supplier and its customers to ensure that the delivered gas is in compliance with the receiving utility's gas quality interchangeability requirements. PG&E proposes that the Commission enact rules requiring all LNG suppliers to process their gas to meet existing utility gas quality interchangeability requirements.

7.1.2. Access on Interconnecting Facilities
with Interstate Pipelines

PG&E also addressed access to Kern River's pipeline expansion that was completed in 2003. The expansion can provide up to 900 MMcfd of new Rocky Mountain gas supplies to flow into California. PG&E states that Kern River also connects to SoCalGas at Wheeler Ridge and at Kramer Junction, but the intrastate capacity made available by SoCalGas to Kern River shippers has proven to be inadequate.

According to PG&E, SoCalGas expanded the Wheeler Ridge interconnect by 80 MMcfd and installed the new Kramer Junction interconnect. The new Kramer Junction interconnect was sized to allow 500 MMcfd of flows from Kern River to SoCalGas. But SoCalGas has only made 200 MMcfd of the 500 MMcfd available for scheduling. The remaining 300 MMcfd is not available because SoCalGas believes shippers on the Transwestern system and El Paso system have grandfathered rights to this capacity. As a result, PG&E states that a significant amount of capacity on the SoCalGas system went unused at Kramer Junction, while the Wheeler Ridge interconnect was constrained for most of the summer of 2003. Since gas from the PG&E system to SoCalGas must also go through Wheeler Ridge, PG&E states that this constraint consistently reduced off-system flows on the PG&E system from June through October 2003.

It is PG&E's position that SoCalGas should not continue to favor shippers on the Transwestern and El Paso system over shippers on the Kern River system. PG&E proposes that until SoCalGas implements a system of firm capacity rights, SoCalGas should implement a process to allocate the take away capacity between all the affected pipelines based on final scheduled volumes from two days prior. This is the same process that is used to allocate the available take away capacity at Wheeler Ridge between PG&E, Kern River, and deliveries from Elk Hills. PG&E urges that its proposal be implemented immediately.

7.2. SoCalGas and SDG&E Proposals

In its proposals, SoCalGas and SDG&E addressed a number of issues associated with providing access to their systems to accommodate both existing and new sources of supply. These include: (1) access options, capacities and costs; (2) ratemaking issues; (3) transmission system integration; (4) firm access rights; and (5) interconnection policies.

7.2.1. Access Options

SoCalGas states that in A.02-12-027 and A.03-09-008, it demonstrated that it has sufficient slack capacity on its backbone transmission system to meet demand through 2020. The magnitude of intrastate facility expansion costs depends largely on the interconnect location of the new or expanded supply source, the size of the new or expanded source, and whether the source is allowed to displace existing supply sources such that the total 3875 MMcfd firm receipt point and redelivery capacity remains the same, or whether the new or expanded interconnect location is allowed to increase the firm receipt point and redelivery capacity of the entire system. The costs that SoCalGas and SDG&E provided in this proceeding are factored estimates, and do not represent detailed construction estimates.

In responding to the OIR's direction that it address the costs of capacity expansion for interconnecting facilities and intrastate pipelines to facilitate LNG supply availability to California at Otay Mesa or at any receipt point in or near the utilities' service territory, SoCalGas and SDG&E examined three locations on their gas transmission system for the receipt of LNG supplies. These are: Otay Mesa meter station on the SDG&E system near the US/Mexico border (potential access by Sempra LNG and Coral); Salt Works Station on the SoCalGas system near Long Beach (potential access by SES); and Center Road Station on the SoCalGas system near Oxnard (potential access by Billiton and Crystal). On a displacement basis, new supplies would have to compete for existing pipeline delivery capacity and potentially displace current supplies, i.e., the SoCalGas system firm receipt and redelivery capacity would remain at 3875 MMcfd. On an expansion basis, the SoCalGas system firm receipt and redelivery capacity would be expanded beyond 3875 MMcfd to accommodate the new supply without displacing the receipt of current supplies.

A number of access cost estimates were provided depending on location, capacity, whether it was on a displacement or expansion basis, and whether it was on a single or multiple receipt basis. The table below illustrates costs related to the potential scenarios:

As shown above and explained in the proposal, improvement costs to accommodate an expansion of the system receipt and redelivery capacity can be significant when compared to improvement costs that assume displacement of capacity.

The OIR also directed SoCalGas to file a proposal for providing additional access for Rocky Mountain supplies to reach California through interconnecting facilities. In A.02-12-027 and A.03-09-008, SoCalGas addressed the facility improvements needed to provide an expansion of 200 MMcfd of additional takeaway capacity at any one of the existing interstate receipt points. As shown in its proposal, a 200 MMcfd expansion would cost $153 million at Topock; $20 million at Blythe; $100 million at Needles; $62 million at Kramer Junction and $100 million at Wheeler Ridge. Any one of these improvements would expand the SoCalGas system receipt and redelivery capacity to 4075 MMcfd. SoCalGas notes that the indicated costs for each location would likely be higher, if more than one of these receipt points is expanded.

In A.03-06-040 it was noted that there is an additional interconnect capacity of 300 MMcfd with the Kern River pipeline at Kramer Junction in existence today. However, that capacity competes for access to the SoCalGas transmission system with existing supplies delivered by El Paso and Transwestern. Thus it is only available on a displacement basis. In order for 200 MMcfd to be accepted and redelivered without displacing other supplies, the $62 million in facility improvements described above are required. The utilities note that their firm access rights proposal would permit an additional 300 MMcfd of supplies to be accepted and redelivered from Kern River on a firm basis in competition with other firm "north desert" deliveries.

7.2.2. Ratemaking

SoCalGas and SDG&E believe there is sufficient total receipt point "slack" capacity in place to serve expected load growth in southern California through 2016. From the perspective of a supply/demand analysis, they believe that adding to the total amount of intrastate transmission capacity during the time horizon to 2016 would be of minimal benefit. However, they believe that investments that provide access to more diversified gas supply sources will be of significant economic benefit to their customers. For example, a new supply source would: (1) increase the reliability of gas supplies in southern California; (2) increase the flexibility of customers' gas procurement by adding another supply option; and (3) increase gas-on-gas competition, creating lower burner-tip prices than would otherwise exist for all customers.

Because of these benefits from supply diversity, SDG&E and SoCalGas recommend that the Commission adopt a policy supporting diversity of supply sources. Specifically, SDG&E and SoCalGas recommend that the following policy statement be adopted:

"It is in the interest of California that new sources of gas supply be encouraged. Therefore, to the extent that the benefits to all utility customers of access to the new gas supplies are greater than the cost to utility customers, the costs of expanding utility backbone facilities necessary to accommodate new gas supplies should be rolled-in to the utilities' system wide transportation rate. Below a certain cost threshold, it should be presumed that benefits exceed cost." (SDG&E and SoCalGas, Phase I Proposal, pp. 69-70.)

SoCalGas and SDG&E state that this policy statement is consistent with the Energy Action Plan's direction on new supply sources and is consistent with FERC policy on rolled-in ratemaking.

In conjunction with this policy statement, SoCalGas and SDG&E propose that if customers express an interest in new or diversified supply sources, SDG&E and SoCalGas would roll-in new or expanded supply access infrastructure costs up to $100,000 per MMcfd of added supply capacity, with a maximum cost for all projects of $200 million. SoCalGas and SDG&E note that the $200 million figure represents a minimum of 2 Bcfd of added receipt capacity at a cost to customers of less than 4 cents per Mcf, or less than one percent of the expected total delivered cost of gas.

The proposed roll-in criteria are based on the price benefits of a more diversified set of supply sources. SoCalGas and SDG&E conducted an analysis of price changes under different demand and basin price scenarios, and investigated the effects of adding a new source of supply to southern California. They assert that a new supply source is a benefit to customers because it creates another option for customers and additional competition to other sources of natural gas supplies. When the new supply source becomes a competitive option to supplies from an expensive basin, there is value to all customers in reduced California border prices. The larger the new supply addition, the greater the opportunity to replace gas supplies from more expensive supply sources and the greater the associated price benefits for all customers.

Since LNG is a new supply source, and based on the diversity benefit analysis, SoCalGas and SDG&E propose to apply the rolled-in ratemaking treatment to LNG projects. They also propose to apply the same rolled-in treatment for expanded access to gas supplies from the Rocky Mountains until the amount of access to this gas is similar to the access to the San Juan and Permian Basins. At that point, they state there would be no additional diversity benefit. While rolled-in ratemaking treatment is not currently proposed for expanded access to San Juan or Permian, the utilities state that if any party can show that the costs of expanding take-away capacity at a receipt point accessing the San Juan or Permian Basins are outweighed by customer benefits, rolled-in treatment should also be considered for such costs.

SoCalGas and SDG&E propose that the revenue requirement changes associated with the rolled-in costs be allocated on an equal cents per therm basis since the net benefits are based on expected gas commodity cost reductions. The projects are intended to provide access to another supply source which results in diversity benefits. Thus, the costs would not be accounted for in the capital dollars authorized in the SoCalGas and SDG&E cost of service proceedings. Also, the costs to be rolled-into rates would not be to meet new customer growth, so the costs would not be accounted for in the annual PBR adjustment mechanism.

SDG&E and SoCalGas propose that a rolled-in ratemaking presumption be established in this proceeding, and that the presumption remain in place until such time the Commission finds that a higher level of utility capital spending on new or diversified supply access is justified.

SDG&E and SoCalGas state they are willing to build expansion or displacement capacity for access to new supplies beyond the capacity that meets the presumption for rolled-in treatment (or which could qualify for rolled-in treatment under a more extensive evidentiary process), for customers or shippers willing to make a long-term commitment to pay the costs of such facilities. As explained in the firm access rights proposal, the open season bidding would be based on a supply curve supplied by SDG&E and SoCalGas using the best estimates available for the cost of constructing added increments of capacity. The capital costs would be converted to a rate per Mcf based on similar factors used to calculate the rolled-in cost except that the costs will be amortized over 15 years.

7.2.3. Transmission System Integration

Currently, SoCalGas has a large transmission system with interconnects to PG&E and all of the interstate pipelines serving southern California. These pipelines access a diverse set of basins, including San Juan, Rocky Mountain, Canadian, and Permian supplies. SoCalGas also provides access to gas from California producers and offshore producers.

All SoCalGas and SDG&E customers schedule natural gas deliveries through the SoCalGas receipt points using SoCalGas' scheduling system. SDG&E has no on-system gas production and receives all gas supplies through interconnects with SoCalGas. The primary delivery point into the SDG&E system is at Rainbow Station in southern Riverside County. Since the merger, the Gas Transmission/Gas Operations group has jointly operated both transmission systems. The utilities assert that this combined operation has led to greater efficiency and reliability for customers in both service territories.

As a wholesale customer of SoCalGas, SDG&E customers currently pay for the use of SoCalGas' transmission system. SoCalGas customers, excluding electric generation customers, do not utilize or pay for SDG&E's transmission system, except for a small share of the Moreno compressor station.

SoCalGas and SDG&E state that the Commission should adopt rules that promote the greatest access to new supply sources for both utility customers. They assert that the most efficient way to accomplish this is to establish an integrated, common access system. The integrated access approach would allow all utility customers in southern California to have the same priority of access, terms, and conditions for natural gas delivered at any point on these two systems.

Under the integrated access approach, SoCalGas and SDG&E customers would continue to schedule natural gas deliveries through the combined SoCalGas and SDG&E receipt points. The customers of both utilities would pay a single integrated transmission rate for delivery from any receipt point to any burner tip location in the combined service area. In addition, customers would continue to pay the separate distribution rates established by each utility for its own service territory.

SoCalGas and SDG&E state that with the development of LNG supplies in Baja California, Otay Mesa could become a significant receipt point for customers of both utilities. It is expected that regasified LNG deliveries to Otay Mesa will provide more natural gas than can be consumed within SDG&E's territory. Therefore, LNG developers are interested in full access to the SoCalGas system and its customers and storage assets. In order to provide these LNG developers with assurance that efficient access to the SDG&E and SoCalGas markets will be available through Otay Mesa, SoCalGas and SDG&E request that the Commission allow the establishment of Otay Mesa as a common receipt point for both utilities by December 31, 2004. Once SoCalGas customers have access to new supplies at Otay Mesa, SoCalGas customers should then pay part of the cost of the SDG&E transmission system, just as SDG&E customers pay part of the SoCalGas transmission system today.

Under the utilities' proposal, the integrated transmission rate would be based on the embedded cost of the combined transmission facilities of the two utilities, including any rolled-in intrastate expansion facilities required to bring new supplies to the market centers. SoCalGas and SDG&E state that on an embedded cost basis, the integrated transmission rate will increase class average transportation rates for SoCalGas customers by 0.2 to 0.4 cents per therm, and SDG&E customers will realize a 2 to 4 cents per therm rate reduction. The Sempra wide electric generation rate will be reduced by approximately 0.2 cents per therm. The utilities propose that specific rate issues be addressed in a second phase of their BCAPs. In the interim, Otay Mesa supplies would be scheduled using SoCalGas' scheduling system, and customers would pay the approved transportation rates of their respective utility for deliveries through this new receipt point.

The utilities claim that the effect on natural gas prices as a result of access to a new supply is likely to be of much greater benefit than the small transportation rate impact on SoCalGas' customers. They also assert that the integrated access rate will establish a reasonable means for SoCalGas' customers to pay for transportation of natural gas through the SDG&E system from Otay Mesa.

Without an integrated access approach, separate receipt points into the SDG&E and SoCalGas systems would need to be established at Otay Mesa and Rainbow Station, respectively. That is, customers in SoCalGas' service territory wanting access to Baja LNG supplies would be required to schedule deliveries through both SDG&E's Otay Mesa and SoCalGas' Rainbow receipt points. SDG&E customers and suppliers wanting access to SoCalGas storage would also be required to schedule deliveries through both receipt points. They claim that the creation of this double receipt point scenario would cause several inefficiencies including loss of operating efficiencies and the creation of artificial pricing advantages for some pipeline delivery points over others, which would distort competition.

The utilities state that if there is an integrated SoCalGas and SDG&E access point, the peaking rate will not apply to customers scheduling deliveries through Otay Mesa. The peaking rate was established to address the pricing and service provisions for customers who partially bypass the SoCalGas system, but remain connected to SoCalGas for their peaking needs. According to the utilities, with transmission integration, customers on both SoCalGas and SDG&E who ship gas through Otay Mesa would not be partially bypassing the utilities' transmission system and the peaking rate would not apply.

However, SoCalGas and SDG&E state that SoCalGas' peaking rate will apply to a partial bypass customer who takes service from an LNG supplier and takes partial service from the utility. If an LNG customer base loads on the LNG supplier and uses the SoCalGas system to meet their peak needs, that customer imposes the same cost on the SoCalGas system as an interstate pipeline customer taking peaking service from SoCalGas. SoCalGas and SDG&E state that the Commission should ensure that LNG customers who choose to partially bypass the utility pay their share of the costs imposed on the utility, as reflected in SoCalGas' cost-based peaking rate.

7.2.4. Firm Access Rights

SoCalGas and SDG&E propose that a system of firm, tradable receipt point access rights be adopted. Such a system will provide assurances to developers of interstate pipeline and LNG projects that their gas supplies will be able to enter the SoCalGas system on a firm basis. The utilities request that the Commission adopt its proposed system of firm tradable access rights as soon as possible. To the extent the Commission concludes that the details associated with firm access rights require evidentiary hearings, the utilities request that the Commission consider such details in Phase II of this proceeding.

SoCalGas explains that its transmission system currently has the capability to take 3875 MMcfd of intrastate and interstate supplies from various receipt points and redeliver those supplies to storage fields and/or distribution customer end-users. This is a firm 365 day a year capability. However, the total supplies that theoretically could reach SoCalGas on a given day exceeds 6 Bcfd based on the capacity of upstream pipelines. SoCalGas claims that, under the current rules, this mismatch makes it difficult to create a reliable firm connection between a supplier and its southern California end use customer for every day of the year. The cost of expanding its receipt point take away capability to 5 Bcfd would be expensive (over $500 million), and in SoCalGas' opinion, unnecessary, because of the available slack capacity.

SoCalGas and SDG&E claim that, instead of making expensive and unnecessary capital investment in the backbone system, there should be a system of firm tradable rights on the intrastate transmission system. A system of firm tradable rights currently exists for PG&E, and SoCalGas and SDG&E claim that a similar system needs to be developed for southern California. The utilities explain that, if ownership rights for the existing 3875 MMcfd of backbone transmission take away capacity can be established, the owners of those rights could establish a firm reliable connection between a particular supply source and the customer's burner tip. The owners of such receipt points could then switch suppliers depending on the price benefits of that supply. New customers or suppliers could bid or trade for those rights through the secondary market to ensure firm deliveries to the SoCalGas city gate.

The Comprehensive Settlement Agreement (CSA) of April 2000 tried to establish such a system. That system, however, was never implemented¹⁴ and, according to SoCalGas and SDG&E, is outdated and deficient for the following reasons:

· First, the rights negotiated during that settlement gave preferences to existing suppliers over new suppliers.

· Second, the term of the CSA rights were limited to less than five years, while the development of new supplies often requires long term access rights.

· Third, the CSA did not provide a framework by which to add new supplies at new receipt points.

· Fourth, the CSA did not describe how SoCalGas might expand backbone transmission capacity.

The utilities state that, relative to the CSA framework, the new proposal should be preferable to customers because: (1) the set asides suggested for core customers look beyond SoCalGas' soon to expire El Paso and Transwestern service agreements and are consistent with the core supply diversity efforts; (2) there is a substantially lower reservation charge, and the resulting revenues are credited back to end users; (3) there is a shorter term commitment required of customers, which allows them to compete for receipt points in new open seasons based on their more recent demand and perceived changes in the values of relative receipt points; and (4) the broader and more flexible definition of receipt point rights by transmission zone will allow customers greater ability to exert downward price pressure on competing gas supplies.

SoCalGas and SDG&E also state that, relative to the CSA framework, the new proposal should be preferable to new gas suppliers because: (1) it puts new gas supplies on a level playing field with existing supplies; (2) it accommodates a variety of potential new supplies at new receipt points; (3) it permits the economic expansion of the transmission system; and (4) it allows new suppliers and/or their customers to obtain long term access to the SoCalGas system so that their large capital investments can be justified.

A four-step proposal to allocate capacity is described in detail in the Phase I proposal of SoCalGas and SDG&E. In summary, for step 1, there would be a set aside option for three years. This step would only apply to existing capacity or potential new receipt point capacity that meets the rolled-in presumption. For step 2, there will be preferential bidding by noncore customers for three years. This step would only allocate existing capacity or potential new receipt point capacity that meets the rolled-in presumption. For step 3 there would be a long-term general auction for new capacity. For Step 4, there would be a shorter-term general auction. In this step any party would be allowed to bid. In steps 3 and 4 any party would be allowed to bid, with the maximum total bid for any party established by its creditworthiness.

SoCalGas and SDG&E also propose the following:

· Associated reservation charge revenue would be credited to all end-users on an equal cents per therm basis.

· Any unawarded firm capacity and daily interruptible capacity would be offered by the utility on a daily volumetric basis for up to 5 cents per dth, and a 75/25 ratepayer/shareholder incentive sharing mechanism would be established for these interruptible revenues.

· The utility would sell interruptible backhaul services from the city gate to any receipt point on its system. This gas could, in turn, then be delivered off system.

· SDG&E and SoCalGas would provide reports to the Commission on the ownership, use, and pricing of the intrastate capacity rights awarded through this process.

· Within a transmission zone, customers would be able to nominate daily on an alternate basis to any of the other receipt points. Alternate receipt rights nominations would be subject to SoCalGas' proposed scheduling and nomination rules.

· NAESB standards would apply for the purposes of bumping of prior scheduled volumes on a cycle-by-cycle basis. SoCalGas will schedule and confirm nominations in accordance with the following priority order: Priority 1 - all nominations utilizing Firm Capacity receipt rights; Priority 2 - all nominations designated as Alternate Receipt Points; Priority 3 - all nominations utilizing interruptible capacity receipt rights.

· There would be no changes to its existing balancing rules in this proceeding. SoCalGas states that new balancing rules are not necessary to implement a system of firm, tradable access rights and intends to address its balancing rules in another proceeding, such as the BCAP.

· The utility would provide for city gate pooling to allow for the aggregation of multiple gas supplies being delivered from multiple receipt points. This pooling location would be on the SoCalGas system after the gas is delivered through a receipt point using the customers' access rights.

· A system-wide in kind transmission fuel rate would be established in order to more accurately signal the variable cost of using the transmission system to market participants. SoCalGas intends to propose such a change in Phase II of this proceeding or in another relevant proceeding such as its BCAP.

7.2.5. Interconnection Policy

Another consideration in promoting access to new gas supplies is the interconnection policy applicable to upstream suppliers, including interstate pipelines and LNG regasification terminals.

SoCalGas and SDG&E propose to interconnect with any new supply source under the following conditions:

1. That the interconnection and physical flows do not jeopardize the integrity of, or interfere with, normal operation of the utility pipeline and storage system.

2. The interconnecting pipeline pays for all equipment necessary to effectuate deliveries at the interconnection, including, but not limited to, valves, separators, meters, quality measurement, odorant and other equipment necessary to regulate and deliver gas at the interconnection point. The interconnecting pipeline must execute a standard Construction/Interconnection Agreement.

3. The interconnecting pipeline must execute a standard Operator Balancing Agreement with the utility. This agreement specifies a number of operating provisions, including minimum and maximum operating pressures, and balancing of actual deliveries and the scheduling of deliveries.

4. Customers and shippers of either pipeline system may use the point of interconnection as a scheduling point if the interconnecting pipeline abides by NAESB nomination/confirmation standards.

5. It will be the interconnecting pipeline's responsibility to deliver supply at the point of interconnection at a sufficient pressure to enter the utility system but at not less than the minimum operating pressure or more than the maximum operating pressure.

6. All supply must meet the requirements of utility's then current Tariff Rule 30 relating to gas quality specifications, or other rules, regulations, and/or requirements of any federal, state, or local or other agency having subject matter jurisdiction, including, but not limited to, the CPUC and the California Air Resources Board.

7. The physical capacity of the interconnection will be determined by the sizing of the point of receipt and the utility's ability to redeliver supply downstream of that point of receipt.

8. The receipt capacity for any particular day may be affected by physical flows from other points of receipt, physical pipeline and storage conditions for that day, and end-use demand.

The utilities state that the approval of this interconnection policy will provide potential new suppliers with a clear understanding of their obligations as they plan their upstream facilities.

7.2. Discussion - LNG Access Issues

Many parties favor the idea of California having the opportunity to access LNG. A number of the parties suggest that it is reasonable to require the utilities to provide open access to LNG facilities. Several parties also favor extending the access policies to new sources of supply other than LNG.

The thrust of a number of the comments, regarding the SoCalGas and SDG&E proposals, addressed the access options and related capacities and costs. Many of the commenting parties believe that a substantial amount of LNG can be accessed for very little money. According to the analyses of SoCalGas and SDG&E, on a displacement basis, up to 400 MMcfd can be accessed through Otay Mesa for approximately $7 million in infrastructure improvements. ORA notes that if the flow on the North Baja pipeline is reversed from west to east, as much as 500 MDth/d could be delivered from Baja Mexico to SoCalGas' Ehrenberg/Blythe delivery point on a firm basis. SoCalGas and SDG&E also estimate that 800 MMcfd of LNG could be accessed through Salt Works Station on a displacement basis, for approximately $5 million in infrastructure improvements; and 800 MMcfd through Center Road Station for approximately $1 million in infrastructure improvements. RACE believes these estimates need to be tested in the course of evidentiary hearings.

PG&E also discussed accessing LNG from Baja California in its Phase I proposal. Assuming regasified LNG flows east to Ehrenberg, as discussed above, it could be accessed if El Paso converts Line 1903 to natural gas service between Ehrenberg, and if PG&E (or El Paso) builds an interconnection between that line and PG&E's Line 300. PG&E did not provide a cost estimate, but in comments NCGC stated it might cost about $100 million.

Other parties, including RACE, NRDC, and to some degree TURN, support the concept of first evaluating through evidentiary hearings California's need for LNG and its ramifications for the state's natural gas market. In a March 9, 2004 motion to modify the procedural schedule, RACE urges the Commission to consider the broader issues relating to California's natural gas needs and supply options before setting policies affecting LNG access and procurement. Among other topics, RACE believes that an evaluation of increasing California's dependence on foreign LNG supplies, the potential reduction in California demand for natural gas-fired electric generation due to increases in energy efficiency and renewable resources, the economic and environmental impacts associated with LNG, the relative inflexibility of LNG supply deliveries, and the effects of community choice aggregation on the utilities' core procurement portfolios, all should be considered before establishing policies designed to facilitate LNG. RACE further states that evidentiary hearings are necessary in order to allow parties to conduct discovery and adequately analyze, critique and respond to the utilities' filed proposals.

The utilities' requests to establish new receipt points to facilitate LNG access, goes beyond the concept of open access based on the current record, and we will not direct the establishment of receipt points at Otay Mesa, Salt Works Station, or Center Road Station at this time. Creating additional receipt points on the utilities' systems is a major policy decision that could create significant operational and ratemaking changes. Indeed, on the SoCalGas system, the change has the potential to be so profound as to reverse the historical north-to-south flow of natural gas around which the system was built. We are not opposed to making such changes; indeed, they may be necessary in order to ensure California evolves with the changing energy marketplace. Rather, we agree with RACE that it would put the cart before the horse to establish additional receipt points to facilitate LNG gas supplies now, without first considering California's future need for natural gas, the other supply options, and alternatives for bringing LNG to the California market (as PG&E has suggested).

In Phase II of this proceeding, we will conduct hearings into these issues, as well as the actual price impacts of LNG in other areas of the United States, projected price impacts of LNG on California natural gas supplies, the deliverability of LNG vis a vis domestically-produced supplies, the impacts of LNG on California's as well as the production, liquification, and regasification area environments, the operational impacts on California's gas utility systems, and any gas quality differences between LNG and our utilities' existing supply sources. We intend to rule on the establishment of additional receipt points after gathering and considering this information.

In general, we favor open access policies and affirm that preference here. Open access helps to ensure reliable supplies and to discourage market manipulation; it also assures developers of new infrastructure that, at a minimum, if they build facilities to the utility's system, the utility will interconnect with those facilities.

The utilities' responses and the comments by parties on the various access options and related costs are relevant to our discussion below regarding the ratemaking treatment for infrastructure improvements.

7.3. Discussion - Ratemaking for
Infrastructure Improvements

SoCalGas and SDG&E propose to roll-in (have ratepayers pay for) up to $200 million in LNG-related infrastructure improvements, as long as the utilities can show that there is a cost benefit in doing so. Both Coral and Sempra LNG, who support the roll-in proposal, intend to deliver regasified LNG to California from Mexico. SoCalGas and SDG&E indicate that to access large amounts of LNG from Mexico through Otay Mesa, related infrastructure improvements could be substantial (e.g., $164 million for 700 MMcfd).

A number of parties oppose the roll-in proposal. Billiton and SES, who propose to provide LNG directly in California, state that they are willing to pay for the costs to access the system, which for like amounts of gas are less than Otay Mesa costs. Billiton indicates that the utilities' proposal effectively results in customers subsidizing the higher cost of entry for Baja LNG and that it is poor public policy to adopt subsidies that saddle ratepayers with potentially hundreds of millions of dollars of cost that can be avoided entirely. SES states that competition based on total delivered prices will result in the construction and operation of LNG facilities in a manner that is most cost effective for the California market.

Crystal, another potential California LNG supplier, states that it is not necessary, as SoCalGas suggests, that presumptions about cost thresholds (such as a rolled-in rate recovery structure) be in place in order to develop new receipt/interconnection points. Crystal states that customers should not be at risk for costs at the outset. Instead, the LNG supplier should be willing and positioned to assume up front cost responsibility. Crystal says that subsequent determinations on rate recovery structures may result in project refunds, if rolled-in pricing ultimately proves to be appropriate, or credit backs if incremental pricing is maintained.

Other parties commented that the utilities' proposal would inappropriately benefit an affiliated company, i.e., Sempra LNG. Regarding access to Baja LNG, ORA also argues that roll-in may not even be necessary, because large amounts of gas, up to 900 MMcfd, can flow from Mexico to California through the combined receipt points of Ehrenberg and Otay Mesa for very little money.

The roll-in proposal of SoCalGas and SDG&E would have the Commission authorize a process by which rates would be increased. However, rate matters are governed by the requirements of Pub. Util. Code Section 454, which requires an application, notice to customers of the proposed rate change, and a finding by the Commission that the new rate is justified. SoCalGas and SDG&E concede that the roll-in proposal will affect customers' rates.

Also, the issue of rolled-in versus incremental ratemaking treatment for particular utility facilities is complicated by the enormous uncertainty regarding LNG projects. Specifically, which facilities will ultimately be developed and when. No LNG terminal or other new supply source has started construction, and projects of this nature face significant hurdles before they can be completed. In addition, potential construction costs to accept and redeliver significant volumes of gas at multiple new receipt points varies widely, depending on which new sources of supply actually materialize and the volumes to be delivered at each new receipt point.

Based on the above concerns, it is appropriate to await the record to be developed in Phase II of this proceeding as well as further developments regarding the permitting and construction of LNG terminals before deciding the extent, if any, to which backbone facility costs should be rolled-in to system-wide transportation rates. Once there is more information about which LNG terminals will actually be constructed and when, the utilities will be able to determine what the true costs of LNG access are. While a number of potential LNG suppliers have indicated that they are willing to pay the access costs, with more detailed and specific cost data, they can make a final determination as to whether they are willing to underwrite the access costs, or if they wish to have the Commission consider rolled-in rate treatment. We will therefore adopt a policy that presumes LNG suppliers will pay the actual system infrastructure costs associated with their projects. However, requests for rolled-in, or any alternative ratemaking treatment, can be filed through the application process, with appropriate notice to customers. Those proposals, including the costs and cost recovery mechanisms, can then be evaluated on a case-by-case basis.

This policy will also apply to PG&E. PG&E proposed an application process on a case-by-case basis, but included the presumption that, if the project were approved, costs would be fully recoverable and rolled-in. Our adopted policy does not have a presumption of roll-in, for the reasons discussed above.

7.5 Discussion - Transmission System Integration

SoCalGas and SDG&E have raised a number of supply access issues, which have rate implications, including that of transmission system integration. The transmission integration proposal would resolve the problem of having two transportation charges if regasified LNG is transported over the transmission systems of SDG&E and SoCalGas to reach gas customers in SoCalGas' service territory. For efficiency reasons, SoCalGas and SDG&E currently operate their transmission systems as a single system. There were no objections to the continuation of this arrangement. Concerns over, and opposition to, the SoCalGas and SDG&E proposal to integrate their transmission systems were principally related to the unknown rate effects of the proposal. In reply, the utilities agreed that rate effects of system integration should be considered in a proceeding devoted to rate matters, such as the BCAP.

SoCalGas and SDG&E should file a separate application to address transmission system integration issues. Both utilities acknowledge in their proposal that the rates of their customers will be affected by the system integration proposal. A utility specific ratemaking proceeding will provide an opportunity for parties to prepare responsive testimony and conduct cross-examination, and ensure conformance with the requirements of Pub. Util. Code Section 454 (a) relating to rate changes. That application should be filed within three months of the issuance of this decision, and it is our intention to address the issue in an expeditious manner.

Some parties commented that the issues associated with system integration are intertwined with the utilities' firm access rights proposal. ORA recommends that the two proposals be addressed simultaneously, since the adoption of a system of tradable firm access rights will likely influence the flow of gas on the various transmission paths. We agree that these two issues should not be decided in isolation. Since, as discussed below, we are also deferring consideration of firm access rights to a separate ratemaking proceeding, the utilities' filing for approval of the transmission system integration proposal should also include its request for approval of firm access rights.

While agreeing that system integration should be examined in a separate ratemaking proceeding, SoCalGas and SDG&E request that the Commission adopt a general policy supporting its proposal, in this decision. There is much to be said for system integration. The utilities cite regulatory and scheduling simplicity. Also, potential operating efficiency problems associated with double receipt points would be eliminated. However, we are concerned with adopting a general policy on system integration without knowing all of the details and ramifications of the proposal itself. For instance, ORA does not agree with system integration at this time, claiming that the utilities are using the potential LNG supply through Otay Mesa as the impetus to seek a Sempra-wide transmission rate. ORA notes that through a reversal of flow, the North Baja Pipeline can move Baja LNG supplies into the SoCalGas system at Blythe/Ehrenberg and customers in the SoCalGas service territory do not necessarily have to use Otay Mesa as a delivery point for LNG supply originating from Baja. Other concerns may develop as the utilities' proposal undergoes further scrutiny.

These concerns need to be fully explored before adopting procedures, rules or any general policies such as those proposed by the utilities. Therefore, at this time, we will not adopt any general policy or principle on system integration. It is however our intention that any solution to transmission access problems will be based on efficiency and fairness to both affected ratepayers and suppliers.

7.6. Discussion - SoCalGas' Peaking Rate

A number of parties commented on SoCalGas' peaking rate, specifically requesting that it be eliminated. The Indicated Producers state that the peaking rate discourages customers from pursuing non-SoCalGas supply sources and is inconsistent with the goal of increasing new electric generation supplies in southern California. Questar indicates that the peaking rate is the only significant obstacle to its provisioning of new incremental pipeline capacity to the Los Angeles load center. SCGC states that if the rate were eliminated, SoCalGas would be subject to competitive discipline in pricing gas transportation service to customers, which would facilitate transportation competition. Calpine and Watson also assert that without a peaking rate, SoCalGas will have stronger incentives to cut costs and to compete to retain and attract loads to its system.

In response, SoCalGas states the peaking tariff allows it to recover the costs of standing by to provide peaking service, to avoid shifting costs from large noncore customers to core customers, and is not anticompetitive as some noncore customers claim. The company explains that under its all-volumetric rate structure, there is a strong incentive for large noncore customers to take base load service from an interstate pipeline company charging straight fixed variable (SFV) rates and only take peaking service from SoCalGas. This is because an all volumetric rate structure does not impose a demand charge on the customer so that, unlike under SFV rates, the customer contributes to the utility's fixed costs of service only when it actually uses gas, even though the facilities necessary to provide the customer's peak demand remain in service. SoCalGas asserts that, unless the Commission keeps the peaking rate or adopts SFV rates for SoCalGas, the regulatory gap between the rates of SoCalGas and the interstate pipelines creates an incentive for large noncore customers to engage in uneconomic partial bypass of the SoCalGas system.

The peaking rate has been reviewed on four separate occasions and the Commission has continued to find that the peaking rate properly discourages uneconomic partial bypass of the SoCalGas system and thereby protects captive core customers. There are significant policies and rate issues associated with the peaking rate and it would be inefficient to address the elimination of the peaking rate again in this OIR. The BCAP has been the forum for addressing such peaking rate concerns in the past and is a proper venue for any further reconsideration of this issue. However, since the peaking rate issue is also related to the transmission system integration proposal, the peaking rate issue may also be raised in the system integration/firm access rights proceeding.

7.7. Discussion - Kramer Junction

Even though SoCalGas' new interconnect with the Kern River pipeline at Kramer Junction is sized to allow 500 MMcfd of flow, there is a bottleneck problem at this interconnect. The bottleneck occurs because SoCalGas gives primary preference to its deliveries on the Transwestern and El Paso pipelines as a result of the agreement reached in the CSA, which was adopted by the Commission in D.01-12-018. For the same reason, shippers on Questar are only assured of 25 MMcfd flowing from Questar onto SoCalGas at North Needles, rather than the 80 MMcfd that Questar is physically capable of delivering. Appendix B of the CSA provides that the existing upstream capacity commitments of SoCalGas' core customers on El Paso and Transwestern can be utilized fully without being reduced by shipper deliveries at other receipt points. As a result of the CSA, SoCalGas limits the receipt of lower priced Rocky Mountain gas from Kern River at Kramer Junction to only 200 MMcfd, instead of what the interconnect is capable of flowing. PG&E, Kern River and Questar complain that this reduces deliveries of lower priced gas into the SoCalGas system by up to 300 MMcfd.

PG&E originally recommended that the Commission adopt a scheduling procedure for Kramer Junction that follows the capacity allocation process used at Wheeler Ridge. The Wheeler Ridge allocation process allocates take away capacity based on final scheduled volumes from two days prior.

SoCalGas cautioned that the Commission should consider the impact of PG&E's proposal on SoCalGas' core customers before ordering SoCalGas to abandon its current scheduling processes. SoCalGas recommended that such a change should only occur when the Commission establishes a system of firm, tradable access rights.

SoCalGas proposed in it's April 6, 2004 Reply Comments to the Draft Decision that if the Commission wants to increase the receipt of Kern River gas while protecting SoCalGas' core customers, the Commission could allow shippers on the SoCalGas system to nominate up to another 300 MMcfd at Kramer Junction whenever less than 1390 MMcdf of supplies are scheduled at North Needles and Topock. Such a process, if adopted, would allow the volumes nominated at Kramer Junction to flow into the SoCalGas system if confirmed by the upstream pipeline.

One of the stated purposes of this OIR is to ensure sufficient gas supplies and infrastructure in order to meet the needs of California's residential and business consumers. If we adopt PG&E's recommendation to use the Wheeler Ridge approach for allocating capacity at Kramer Junction, there is no assurance that the core gas needs of SoCalGas will be met by using this capacity allocation method. Although we are keenly aware of the need for lower priced gas supplies, we do not believe that the primary preference for gas flows over Transwestern and El Paso should be eliminated at this time.

We will adopt SoCalGas' updated proposal as explained in the August 16, 2004 reply comments of SDG&E and SoCalGas and in Appendix A of those reply comments. Under the updated proposal, which replaced SoCalGas' April 6, 2004 proposal, SoCalGas proposes to allocate receipt point capacity based on the physical capacities and expected flows of SoCalGas' North Desert Transmission Zone (Kramer Junction-Kern River, Topock-El Paso, North Needles-Transwestern, North Needles-Questar, and Hector Road-Mojave). If Cycle 2 scheduled quantities exceed the North Desert transmission capacity of 1590 MMcfd, volumes would be reduced at the Kramer Junction and Questar receipt points in Cycle 3 in order to allow SoCalGas' core supplies to flow from El Paso and Transwestern. In the event scheduled quantities do not exceed the North Desert transmission capacity, additional gas supplies from Kern River and Questar will be able to flow into the SoCalGas system. The procedures to which SoCalGas plans to adhere are discussed and illustrated in Appendix A of the reply comments, a copy of which is attached to this decision as Attachment A. SoCalGas' updated proposal should result in more Rocky Mountain gas supplies flowing onto SoCalGas' system, while allowing SoCalGas' core supplies to flow. SoCalGas shall be directed to follow the procedures outlined and illustrated in Attachment A of this decision and to make this change to its scheduling practices as soon as possible.

We also note that this problem at Kramer Junction and North Needles is likely to be eliminated if the Commission adopts a system of firm tradable rights, and as the capacity contracts with Transwestern and El Paso expire.

7.8. Discussion - Firm Access Rights

The response to the SoCalGas and SDG&E firm access rights proposals varied from full support, to a claim that the proposals are beyond the scope of this proceeding and should be stricken. Many parties expressed concerns about certain aspects of the proposals, such as set asides, the level of reservation charges, the need to first unbundle the transmission network, the need for a price cap on secondary market transactions, and the auction process. Other parties found the proposals to be too complex and potentially too controversial to be resolved without further analysis. There was a general sentiment that the issues need to be addressed more fully through evidentiary hearings in either Phase II of this proceeding, the BCAP or other separate proceeding.

In D.04-04-015, we stated our general support for firm access rights for SoCalGas and implemented the CSA's proposal. However, that order was stayed pending a decision in Phase I of this OIR. As explained in their OIR responses, SoCalGas and SDG&E claim, and some other parties agree, that many of the elements of the CSA proposal are now outdated and should not be implemented.

Today's decision also makes a change to SoCalGas' transmission system which should be considered, namely, to increase the flow of gas from Kern River through the Kramer Junction interconnect.

The effect of these changed circumstances on the firm access rights that we adopted in the CSA, and how this relates to the SoCalGas and SDG&E proposals, need to be examined. We find that evidentiary hearings are needed to fully develop the record and to respond to concerns raised in the comments of the other parties. We will therefore not adopt any proposal for firm access rights in this decision. Instead, as stated in our transmission system integration discussion, SoCalGas and SDG&E can file an application regarding its system integration and firm access right proposals. We will therefore continue the stay of D.04-04-015 until further notice.

SoCalGas and SDG&E recommend that if evidentiary hearings are deemed necessary on the firm access proposals, the Commission should at least adopt the following policies in this Phase I decision:

· New gas supplies should have the opportunity for equal access into the utility system

· New gas supplies should be allowed to compete on an equal footing with existing supplies.

The proposed statements are unopposed. They reasonably reflect our intentions to facilitate the development of alternative supplies and will be adopted.

7.9. Discussion - Off-System Deliveries

PG&E's Phase I proposal states that one manner in which its customers could gain access to LNG supplies from southern California would be if SoCalGas were to allow nominations from a Los Angeles city gate delivery point to an off system connection with PG&E. Initially this might be accomplished through displacement, and later by physically transporting LNG supplies to PG&E's system. A number of other parties also supported off system sales procedures.

SoCalGas indicates that PG&E's request is consistent with its proposals for a system of firm access rights that would create a city gate market and to sell interruptible backhaul services from the city gate to any receipt point on its system, where that gas could, in turn, then be delivered off system. While SoCalGas did not address the issue of firm off-system deliveries, which is equivalent to PG&E's discussion of physical deliveries of gas by SoCalGas to PG&E, it agrees that such deliveries might be necessary and indicates that it is evaluating the cost of facilities necessary to provide firm off-system deliveries along with an appropriate transportation rate and terms for such deliveries. SoCalGas should make its full showing on off-system deliveries in its upcoming system integration/firm access rights filing. This showing should be limited to off-system deliveries for natural gas to be consumed within California (e.g., into PG&E's service territory). Several parties who commented on the draft decision recommended that SoCalGas be allowed to make off-system deliveries to points other than PG&E. Since the focus of this OIR is to ensure that the natural gas needs of California's residential and business customers are met, SoCalGas' off-system deliveries should be limited to PG&E.

7.10. Discussion - Interconnection Policy

SoCalGas and SDG&E have proposed interconnection policies and indicated that they are unopposed and should be adopted. We note however that PG&E's proposal includes a recommendation that it and ultimately ratepayers should fund interconnections with LNG facilities. This conflicts with PG&E's current interconnection policies, as well as with the SoCalGas and SDG&E proposal, which requires all interconnection facilities be paid for by the interconnecting pipeline. At this time, PG&E's proposal is moot, since there are no potential LNG suppliers that would interconnect to PG&E, on the horizon. We also note that one policy that we are adopting and which appears to be supported by most parties, is that new gas supplies should be able to compete on an equal footing with existing supplies. Subsidizing LNG interconnections would be contrary to that policy. Therefore, we will not adopt this aspect of PG&E's proposal. The SoCalGas and SDG&E proposed policy should apply to all three utilities.

Interconnection policies were also the subject of the supplemental comments, which are discussed below.

7.11. Discussion - LNG Supplemental Issues

The Scoping Memo requested additional comments on the following LNG access issues:

1. What are the operational balancing agreements that have been or should be offered by respondents to the sponsors of the proposed LNG projects?

2. Should the respondents be allowed to have different provisions concerning quality specifications in their proposed operational balancing agreements for LNG projects, than the provisions concerning quality specifications in their Commission-approved tariffs?

3. Are there any other access issues involving potential LNG supplies, which have not yet been addressed and which would otherwise be left to the discretion of the respondents? If so, please identify the issues and propose how the Commission should address the issues.

Fifteen supplemental comments and seven supplemental reply comments were filed.

The operational balancing agreement addresses operational issues between the interconnecting pipeline and the gas utility's pipeline transportation system. It covers such topics as "scheduling practices, minimum and maximum pressure requirements, balancing, and compliance with gas quality standards established by this Commission and by other authorities." (SDG&E and SoCalGas, Initial Comments, p. 3.)

Regarding the first question about the operational balancing agreements, most of the parties state that all LNG shippers should have open and equal access to the gas utility's pipeline on a nondiscriminatory basis. Some of the parties point out that to do otherwise will provide one source of gas supply with an advantage over another, and lead to an uneven playing field. Several of the commenting parties recommend that the utilities submit model operational balancing agreements to the Commission for review and approval in an open manner.

SDG&E and SoCalGas support having standardized terms and conditions for providing access to all new upstream pipelines, including the terms and conditions associated with the operational balancing agreement. They recommend that the Phase I decision state that all upstream suppliers will be treated equally with respect to access into the utility's system, including equal treatment on the terms and conditions of the operational balancing agreement. They also request that the Commission approve as part of the Phase I decision, their proposed interconnection policy, which contains the interconnection requirements that should be met by all new upstream pipelines.

SDG&E and SoCalGas attached a proposed pro forma operational balancing agreement to its comments on the supplemental LNG questions. They propose that this pro forma agreement be used as the basis for Commission approval of a standardized operational balancing agreement. SDG&E and SoCalGas state that having a standardized agreement will assure market participants that no particular upstream pipeline will receive preferential access over another upstream pipeline. They recommend that the Commission initiate an expeditious review of the proposed pro forma operational balancing agreement.

PG&E states that the Commission should not adopt a generic or statewide operational balancing agreement because of the different interconnection points that exist on its system. PG&E advocates that the operational balancing agreement should be left to the LNG project operator and PG&E to finalize. Other parties voiced similar concerns.

Several parties state that LNG supplies may lead to a situation where LNG supplies need preferential capacity due to the delivery timing of LNG supplies. Lodi states that the operational balancing agreement should not allow the LNG suppliers to reserve capacity for every day that it needs it, and to pay for it only when it is used. Instead, the Commission should ensure that the LNG supplier is treated like any other gas supplier, and be "subject to either a priority use scheme that applies to everyone, or to a demand charge to reserve capacity that includes the cost of reserving capacity every day but also allows the subscriber to resell that capacity to others, or to use it flexibly, e.g., to put part or all of the LNG in storage and use it at times when the tanker is not offloading to bring gas back out of storage." (Lodi, Initial Comments, pp. 3-4.) RACE states that "LNG suppliers should incur the costs of bringing an inflexible supply of natural gas onto the system." (RACE, Comments, p. 2.)

Some of the parties point out that there are likely to be some operational issues, which the utility and LNG shipper might have to work out on an individual case-by-case basis.

We will include in the Phase II hearings of this proceeding consideration of standardized operational balancing agreements to connect all new upstream gas pipelines that interconnect with the pipelines of SDG&E and SoCalGas, and to address the concerns raised by the parties regarding the use of a standardized operational balancing agreement.¹⁵ Having a standardized agreement could help ensure that all upstream gas pipelines are treated on the same terms and conditions, and ensure that the upstream affiliates of SDG&E and SoCalGas will not be given any preference in their interconnection arrangements.

The second issue which the scoping memo seeks comment on is whether LNG supplies, when regasified, should meet different gas quality specifications than the gas quality specifications that are in the respondents' Commission-approved tariffs. The gas quality issue is important because it can affect the safety and performance of gas-fired household appliances, manufacturing equipment, turbines, and compressed natural gas (CNG) vehicles. In addition, gas quality specifications can be affected by applicable air quality standards.

Billiton is concerned that in its discussions with SoCalGas concerning an operational balancing agreement, that SoCalGas has insisted that Rule 30 apply, and that the LNG supply also meet "other rules, regulations and/or requirements of any federal, state, or local or other agency having subject matter jurisdiction, including but not limited to the CPUC and California Air Resources Board." (Billiton, Comments, p. 4.) Billiton has no objection to meeting Rule 30, but is concerned that it may have "to comply with any and all unspecified rules or regulations that may be imposed at any time in the future by any unspecified agency." Billiton is concerned that such language could require it to meet future vague and unspecified future gas quality specifications, instead of the utility's gas quality specification tariff.

Sempra LNG mentions that if a waiver of any of the gas quality specifications or other interconnection requirements are needed, that the utility should "ensure that such a waiver would not cause any material adverse impact to the utility system or its operation," and if "no adverse impact would result, the requested waiver should be submitted for the Commission's approval by way of advice letter." (Sempra LNG, Initial Comments, pp. 1-2.) Coral also advocates that if an upstream supplier seeks to deviate from a specification, that the waiver should be granted "by the Commission if it is determined that a deviation from the utility's existing tariff will not compromise the integrity of the utility's transmission and distribution system or interfere with the gas-burning equipment of customers served by the utilities." (Coral, Opening Comments, p. 4.)

Lodi states that gas suppliers who have the capability to blend "out of spec" gas into "spec gas" should be allowed to do so, and that this should be facilitated by the regulated infrastructure to the extent it is feasible to do so.

RACE is concerned that if an LNG supply is allowed to meet different gas quality standards, that this will result in either of the two following negative outcomes:

"1) `hotter' LNG gas is blended into pipeline trunklines, resulting in an incremental increase in bulk Btu content that is still within the quality specifications in the utilities' Commission-approved tariffs but that results in incremental increases in NOx emissions from uncontrolled combustion sources using the gas (stoves, hot water heaters, etc.), or 2) the `hot' LNG is proposed to remove propane and ethane at the regasification terminal, as proposed by Mitsubishi in Long Beach, potentially exposing the local population to greater risk in event of a major accident than would otherwise be present."

SDG&E and SoCalGas comment that the existing gas quality specifications should not be changed unless it can be shown that the modifications will "not adversely affect health, safety, utility system integrity, or utility operating procedures." (SDG&E and SoCalGas, Initial Comments, p. 2.)

The comments note the various work that SoCalGas and others are involved in regarding LNG gas quality. The use of regasified LNG to fuel electric generation plants, and as CNG to fuel gas-fired vehicles, will involve the California Air Resources Board and the regional air quality districts. The CEC, the FERC, the utilities, and industry groups have also been studying this issue.

There are a number of ongoing activities studying the issue of LNG gas interchangeability. The Commission should coordinate statewide efforts with the CEC and other state agencies and conduct a workshop to thoroughly examine gas quality issues in the near future. The workshop process will provide participants and the Commission with a forum to examine the gas quality specifications and the related concerns in detail. The Energy Division is directed to submit into the records of this proceeding a workshop report for comments by all interested parties

All of the parties who addressed the gas quality issue agree that LNG shippers should have to meet the same gas quality specifications contained in the utility's tariff provisions. Until we decide whether the current gas quality specifications should be changed, all gas supplies entering the respondents' gas systems must continue to meet the current applicable gas quality specification tariff. It is our belief that the applicable utility's gas specification tariff should be the governing document regarding all of the gas quality specifications that the gas supplier must meet. Therefore, any changes to the gas quality specifications should be subject to the Commission's approval and reflected in the utilities' tariffs.

The comments regarding other access issues involving potential LNG supplies mentioned two issues. The first is that the introduction of LNG supplies will have system-wide implications, and that the gas flow on the various pipelines are likely to change significantly. This is likely to occur even if no West Coast LNG terminals are built, but LNG terminals are built in the Gulf of Mexico or on the East Coast. If LNG terminals are built to serve the gas needs of the eastern states, this is likely to result in more domestic gas supplies being made available to California.

Some of the Phase I proposals have noted that certain pipelines may have to be enlarged or additional equipment may be needed if LNG supplies on the West Coast are connected to the respondents' gas transportation system. The parties have also mentioned that gas flow patterns could change depending on which pipelines LNG gas suppliers have access to. Today's decision reflects those considerations. The Phase II hearings will address these issues in detail. Similarly, by not adopting the proposal to roll-in costs, all possible transportation options will be left open. Should a respondent seek to file a roll-in application, or an application to expand its system to accommodate the LNG supply, we will look at the impact of such proposals. In addition, by supporting a diverse supply of gas, we leave the door open for accessing reliable supplies of gas at competitive prices.

Lodi states that all of the components of the state's gas-delivery infrastructure should be made available on flexible terms. Lodi contends that this will allow customers to optimize the available services to meet their particular needs.

Most, if not all, of these issues will be addressed in the firm access rights proposal, or elsewhere in Phase II.