IV. Firm Access Rights
A. Introduction
This phase of the proceeding addresses the latest proposal of SDG&E and SoCalGas to have a system of FAR apply to their transmission system. Some parties support the utilities' FAR proposal with modifications, while other parties oppose the FAR proposal and recommend that the current system remain in place or that competing proposals be adopted.
There are four main proposals to change the current gas market structure for SDG&E and SoCalGas. The first proposal is the utilities' FAR proposal. The second proposal is the unbundled FAR proposal sponsored by several other parties. The third proposal is the Joint Proposal sponsored by other parties, including most of the LNG project developers. The fourth is a proposal of the Division of Ratepayer Advocates (DRA) in the event the Commission decides to adopt a FAR system. Many of the parties who participated in the proceeding propose assorted modifications to the various proposals should one or more of the proposals be adopted by the Commission.
In the sections that follow, we describe the current capacity allocation system, each of the proposals and the criticisms and proposed modifications to each proposal, followed by our discussion of the FAR issues.
B. Current System
The integrated transmission system of SDG&E and SoCalGas has the capability to take 3,875 million cubic feet per day (MMcfd) of intrastate and interstate gas supplies from the receipt points on the system and to deliver those supplies to end-users or gas storage fields. This take-away capability is greater than SoCalGas' annual average load, which in 2005 was approximately 2,500 MMcfd. The total supplies on the interstate upstream pipelines that can theoretically reach SDG&E and SoCalGas on any given day are 5,675 MMcfd. If new gas supply sources come to fruition, the upstream delivery capability is expected to increase. Due to the difference between the delivery capability of the upstream gas supplies and the take-away capacity of the receipt points on the SDG&E and SoCalGas system, problems in the delivery of one's gas supply can result from what the parties refer to as a "mismatch" or "bottleneck."
Under the current system, the end-use customer is the only one who can transport gas over the SoCalGas and SDG&E systems. SoCalGas allocates receipt point capacity to the upstream interstate pipelines daily. It is then up to the upstream interstate pipelines to allocate that capacity among its shippers using the capacity allocation rules of the upstream interstate pipelines, which have been approved by the Federal Energy Regulatory Commission (FERC). In the event the shippers' volumes on the interstate pipeline exceed the physical take-away capacity of a specific receipt point, the upstream shippers' contractual rights govern whose gas will flow on that particular day. Such an allocation process can result in a situation where access to the SDG&E and SoCalGas systems are available only on an interruptible basis, and the shippers' gas supplies are pro-rated. In addition, constraints at a receipt point can reduce the amount of upstream supplies that can enter through a particular receipt point.
SDG&E and SoCalGas point out that many of their receipt points interact with other receipt points within certain transmission zones. As a result, whenever the combined supplies flowing through the multiple receipt points exceed the take-away capacity in a particular zone, SoCalGas has to allocate the total available transmission zone capacity to each of the upstream pipelines. Under the current system, this process results in the grandfathering of a preference for gas supplies from El Paso Natural Gas Company (El Paso) and Transwestern Pipeline Company (Transwestern) in the Northern transmission zone over other suppliers in that zone. For the Wheeler Ridge transmission zone, the allocation of receipt point capacity is based on the previous day's total flow at Wheeler Ridge. As a result, the Wheeler Ridge allocation process means that a shipper who is flowing gas on a constant daily basis may be cut on a subsequent day because of the actions of other shippers who reduced their flows during the prior period.
SDG&E and SoCalGas contend that the current allocation methods frustrate both suppliers and end-users, create confusion in the marketplace, and do not necessarily allow the lowest cost gas to reach the end-use markets.
C. SDG&E and SoCalGas FAR Proposal
SDG&E and SoCalGas are proposing a system of tradable FAR13 which govern whose gas supplies get to flow into the five transmission zones which make up their integrated transmission system.14 Using a three-step open season process, the FAR proposal would allocate access rights to the capacity at a particular receipt point to various market participants on a firm basis. All unutilized firm receipt point access capacity would be made available on an interruptible basis. SDG&E and SoCalGas contend that their FAR proposal will eliminate the unpredictable pro-rationing that occurs under the current system when the upstream pipelines allocate the available capacity on the SoCalGas system.
Under the FAR proposal, the holder of the FAR would be entitled to firm receipt point access at a particular receipt point. This allows the holder to ship its gas onto the SDG&E and SoCalGas transmission system at the specified receipt point for shipment to the specified delivery point. The following four delivery points are available under the FAR proposal: (1) to an end-user pursuant to an end-user's local transportation agreement; (2) to a citygate pool account; (3) to a storage account; or (4) to a contracted marketer or core aggregator transportation account. (Ex. 15, Schedule No. G-RPA, Delivery Points.) The FAR assures the holder that its designated gas will flow to the specified delivery point.
Under the FAR proposal, the FAR holder will have first priority in scheduling nominations to the receipt point. The FAR proposal also allows the holder of the FAR to exercise the FAR at another receipt point within the same transmission zone on an "alternate firm basis."15 In response to parties' concerns, SDG&E and SoCalGas are also willing to allow the FAR to be used for out-of-zone receipt points without an additional charge, which would be scheduled after alternate firm nominations within a zone.
SDG&E and SoCalGas propose that a reservation charge for the FAR be set at five cents per Dth per day. This reservation charge is payable each month regardless of the quantity of gas scheduled during the billing period. SDG&E and SoCalGas propose that the five cents per Dth reservation charge be credited back to their end-users, which has the effect of reducing the transmission rate for end-users. Under the FAR proposal, the transmission and distribution costs remain bundled and are included in the cost of the system integrated transmission rate.
For interruptible receipt point access service, SDG&E and SoCalGas propose that they be allowed to charge a volumetric rate of up to five cents per Dth. SDG&E and SoCalGas propose that a 90/10 ratepayer/shareholder incentive sharing mechanism, with a $5 million per year cap on the shareholder portion, be established for interruptible revenues. They contend this will provide an incentive to ensure that the maximum amount of interruptible capacity is offered, and to ensure that firm capacity cannot be profitably withheld from the secondary market.
In addition to the reservation charge, SDG&E and SoCalGas propose an in-kind fuel charge of 0.28% on the gross scheduled quantities of gas specified in the customer's Receipt Point Access Contract. The fuel charge reflects the cost of the compressor fuel used to move the gas from the receipt point to the citygate.
The utilities' FAR proposal calls for a three-step open season process for the initial allocation of FAR at the existing and new receipt points. The open season process would take place every three years. The testimony contained in Exhibit 15, and proposed Schedule No. G-RPA in Exhibit 15, describe the three-step open season process in more detail. We summarize the process in the paragraphs that follow.
In Step 1, the FAR proposal calls for a set-aside of FAR for retail and wholesale core customers, Core Transportation Aggregators (CTAs), holders of certain long-term contracts, and California gas producers. The Step 1 set-aside is for a period of three years.
The set-aside for retail core customers is on behalf of SoCalGas' core customers and SDG&E's core customers. They would receive a FAR set-aside in Step 1 to match their qualifying upstream pipeline contracts. SDG&E and SoCalGas' Gas Acquisition Departments would be charged the five cents per Dth per day reservation charge under the G-RPA1 rate schedule.
Other wholesale customers who serve core loads would have the option to elect to receive a set-aside based on their qualifying upstream interstate pipeline commitments. If the wholesale customer selects the set-aside option, the option would apply to all eligible core quantities. These wholesale customers would be charged the reservation charge under the G-RPA1 rate schedule. If the wholesale customer elects not to select this set-aside option, the customer would be responsible for deciding whether to bid for FAR in Steps 2 and 3.
For the wholesale customers' noncore customers, a wholesale customer may elect to have its noncore customers participate directly in Steps 2 and 3, or it can elect to participate in the open season process on behalf of its noncore customers' requirements.
The CTAs will have the option to receive a FAR set-aside based on their qualifying upstream interstate pipeline commitments. If a CTA elects to receive the set-aside, it must do so for all eligible quantities. CTAs would be charged the reservation charge under the G-RPA1 rate schedule. If the CTA elects not to receive the set-aside, or the set-aside is less than the CTA's historical demand, the CTA would be responsible for deciding whether to bid for FAR in Steps 2 and 3.
For a customer who has a Commission-approved long-term firm transportation contract for firm deliveries at a particular receipt point, which contract is in effect at the time the FAR system is implemented, that customer will have the option to receive a FAR set-aside at the specified receipt point. The quantity of the set-aside would be based on the daily quantities specified in the contract. According to SDG&E and SoCalGas, there are currently four contracts that meet these criteria for a total quantity of 80 MMcfd in the Wheeler Ridge transmission zone. Those customers electing the set-aside would be charged the reservation charge under the G-RPA1 rate schedule but would receive an equivalent credit on their monthly bill to account for the payment of the reservation charge. Any customer who chooses not to receive the set-aside may participate in Steps 2 and 3 like other noncore customers.
California gas producers whose facilities are connected directly to Line 85, the Coastal transmission zone, or another system where there is not an identified receipt point, would receive a set-aside option for a quantity up to their individual historical peak month production delivered into the SoCalGas system in the base period. These producers may elect all or a portion of the peak month deliveries as the set-aside quantity, and they would be charged the reservation charge under the G-RPA1 rate schedule. The California producer set-aside on Line 85 is estimated at 140 MMcfd, and 100 MMcfd on the Coastal transmission zone.
Step 2 provides for end-use customers16 or their designated agents to bid in an open season for up to 75% of the capacity at each existing receipt point, minus any capacity that has been taken as a set-aside. There would be three rounds of bidding. The end-user's maximum bidding rights for such capacity would be based on a base load maximum plus a monthly peaking maximum over a base period. The base load maximum is based on the customer's average daily historical consumption during the base period.17 Customers would be awarded as much of the capacity that they requested subject to the 75% limitation and the limit of the capacity in the zone. If the capacity bid exceeds the available capacity at a particular receipt point or transmission zone, all bids would be pro-rated. In awarding receipt point access capacity in Step 2, a preference would be given to annual base load bids over monthly bids. The contract period for Step 2 capacity is for three years. The reservation charge under the G-RPA1 rate schedule would apply.
Step 3 of the FAR proposal calls for an open season for the remaining existing receipt point capacity, expansions at existing receipt points, and new receipt capacity at new receipt points at Center Road, Salt Works, North Baja Pipeline at Blythe, and Otay Mesa, or other new receipt points that become available prior to each open season cycle.18 Step 3 would be open to all creditworthy market participants. Participants would be allowed in a single bidding round to submit annual base load receipt point access bids. As originally proposed, the contract term for Step 3 capacity is 15 years. At the end of the term, the holder would have a right of first refusal.
The contracts for existing capacity would incur the reservation charge under the G-RPA1 rate schedule. The contracts for new receipt point capacity would be charged the reservation charge under the G-RPA1 rate schedule, plus the specific reservation charge for the cost of the necessary incremental facilities under the G-RPA2 rate schedule.
Once a contract is executed for the new receipt point capacity, an upfront payment of the estimated costs will be required prior to the commencement of the construction of the required facility enhancements.19 This payment will be charged to all 15-year contract holders on a pro-rata basis. In the event this new capacity is approved by the Commission for rolled-in ratemaking treatment, the contract holders would be permitted to relinquish the capacity before the end of the contract term and be relieved of the associated reservation charges.
If there is sufficient customer interest in expanding the receipt point capacity or expanding the take-away capacity from a receipt point or transmission zone, SDG&E and SoCalGas would conduct an open season using the Step 3 process.
After the three-step open season process is completed and SoCalGas posts the available receipt point access capacity on its electronic bulletin board (EBB), the holders of the FAR would be allowed during a two week period to "re-contract" any part of their FAR capacity from their designated receipt point to a different receipt point in the same transmission zone or in a different transmission zone, so long as capacity is available at the requested receipt point. At the end of the two-week period, SoCalGas will evaluate all requests for changes and grant the requests where receipt point capacity is available. If more capacity at a particular receipt point or transmission zone is requested than is available, SoCalGas will pro-rate the requests among the requesting holders.
Following the re-contracting process, SDG&E and SoCalGas propose to post all remaining firm receipt point capacity on their EBB. Any creditworthy market participant may acquire available capacity on a first-come, first-served basis for a minimum term of one month and a maximum term up to three years at the G-RPAN rate. SoCalGas would also be allowed to post the availability of monthly receipt point capacity at a negotiated level below the G-RPA1 rate, and to hold an open season for that capacity. If the bids are in excess of the posted receipt point access capacity at a particular receipt point or within a particular transmission zone, the participant awards will be pro-rated so that the awarded receipt point access capacity does not exceed the available capacities.
Under the FAR proposal, all unutilized firm receipt point access capacity will be made available on an interruptible basis at the G-RPA1 rate, and will be scheduled in accordance with SoCalGas' Rule 30 for interruptible capacity. SoCalGas would also have the flexibility to post the daily interruptible volumetric charge at a level below the G-RPA1 rate for all interruptible receipt point service or just for a particular receipt point. If this is done, all interruptible service used by customers at the designated receipt point on that day will be charged the reduced volumetric charge.
The FAR proposal also calls for a secondary market, utilizing an electronic trading platform on the EBB, where a FAR holder can release and sell all or a portion of its FAR, and where a creditworthy party may purchase a FAR. The details of how this secondary market would operate are described in Exhibit 15 at pages 26 to 29, and in proposed Schedule No. G-RPA in Special Conditions 12 to 17.
Upon the implementation of the FAR system, SDG&E and SoCalGas propose to terminate any remaining Wheeler Ridge Access Agreements with Southern California Edison Company (SCE) or SDG&E and to eliminate the G-ITC rate schedule.20 These access agreements require SoCalGas to make available a specific amount of daily access capacity through Wheeler Ridge, but do not provide any specific FAR to either SCE or SDG&E.
SDG&E and SoCalGas are not proposing an ownership limit on FAR capacity or that there be price caps in the secondary market. They believe these kinds of measures are unnecessary because of the trading opportunities in the secondary market and the availability of interruptible service.
To assist the Commission in addressing market power concerns, SDG&E and SoCalGas propose that quarterly reports be provided to the Commission. The reports would provide information about the intrastate capacity rights held by market participants, such as the name of the entity holding the FAR, the volume held, usage of the rights, and the terms of those rights. The same information, except for usage, would also be posted on the EBB and updated on a daily basis.21 Should the Commission determine that the market is not functioning in a sufficiently competitive manner, the Commission would be free to impose price caps or ownership limits, or to order SDG&E and SoCalGas to release a portion of a participant's FAR should market concerns arise.
SDG&E and SoCalGas propose that the implementation of the FAR proposal and other proposed services occur over a 12-month period following a final Commission decision.22 They point out that the overall implementation schedule depends on the enhancements to their information and computer systems. Time is also needed to provide information to and to educate their customers about the FAR system and new service offerings. The schedule also allows end-users to work with their marketers and agents to formulate their procurement options.
The cost to implement the FAR system and the other services described above are estimated at $3.5 million. SDG&E and SoCalGas propose that a memorandum account, the FAR Memorandum Account, be established to track the implementation costs.
2. Criticisms and Proposed Modifications to the FAR Proposal
Various parties criticize or seek modifications to the FAR proposal of SDG&E and SoCalGas.23
DRA favors the retention of the current system because it believes the ratepayers of SDG&E and SoCalGas will be better off. DRA contends the FAR proposal is less flexible and would increase the risk of higher prices because of reduced gas-on-gas competition. DRA also contends the FAR proposal is too burdensome because of the three-step open season process. DRA further contends that the reservation charge has no cost basis, that it will increase the cost of gas, and that the credit back will not lead to a decrease in rates. If the Commission intends to adopt a system of FAR, DRA proposes that its firm rights allocation method be adopted. DRA's proposal is described in more detail below.
Clearwater Port LLC (Clearwater) contends that the FAR proposal is, in many respects, consistent with the principles of open and non-discriminatory access to the California gas markets. Clearwater, however, recommends that certain aspects of the FAR proposal be amended in order to ensure fair competition between all suppliers of natural gas. Clearwater proposes the following amendments: that all existing excess capacity be made available to all potential users on a non-discriminatory basis; that alternate FAR should be usable at any alternative receipt point in any transmission zone; that the bidding on new expansion capacity take place in Step 3 only; and that penalties should be imposed on anyone who artificially nominates deliveries in an effort to limit secondary market access to system capacity.
Watson Cogeneration Company, the Indicated Producers, California Cogeneration Council, and the California Manufacturers and Technology Association (Watson/IP/CCC/CMTA) assert that the FAR proposal will move rates away from the cost of service because there is no unbundling of costs and because of the arbitrary five cents per Dth reservation charge. The FAR proposal also discriminates among shippers because they do not receive the credit back of the reservation charge. Watson/IP/CCC/CMTA point out that the FAR proposal has limited market benefits, and allows the utilities' shareholders to receive annual revenue incentives of up to $10 million.
In the opening and reply comments to the ALJ's proposed decision, several parties recommend that if the Commission adopts the FAR reservation charge of five cents per Dth, instead of the 15.75 cents per Dth charge, that the Commission should unbundle the five cents FAR charge from the end-user's volumetric transmission rate. By doing so, FAR holders will contribute towards the costs of the transmission system, and there will be no need for the utilities' credit-back mechanism, which would only credit end-users with the five cents FAR reservation charge.
Watson/IP/CCC/CMTA propose that the unbundled FAR proposal be adopted instead. Since the 15.75 cents per Dth reservation charge reflects the cost of the noncore backbone transmission service, no credit back mechanism is needed and the remaining transportation rate will be lower. The unbundled FAR proposal also places the utilities at risk for recovery of the noncore backbone transmission costs, which balances risk and the opportunity for reward. Watson/IP/CCC/CMTA contend that its proposal will facilitate the creation of a citygate market in southern California.
Coral Energy Resources, L.P. (Coral Energy) opposes the FAR proposal. Coral Energy contends that a system of FAR for existing receipt point capacity is not needed. Since the customers of both SDG&E and SoCalGas have paid for existing receipt point capacity, all customers should continue to have equal access to the existing receipt point capacity. Coral Energy contends that a system of FAR could limit an end-user's gas supply options as compared to the current receipt point allocation structure.
Coral Energy contends that the current system provides a rational basis for allocating existing receipt point access during periods of capacity constraints. The protocols in place for allocating and scheduling nominations at constrained receipt points have been effective, and do not require shippers to pay a reservation charge as they would under the FAR proposal. Coral Energy contends that any receipt point allocation structure should be limited to providing firm access to new or expanded receipt point capacity to those entities that bear the incremental costs, as provided for in the Joint Proposal.
BHP Billiton LNG International Inc. (BHP) is in favor of continuing the current system. BHP also favors the adoption of the Joint Proposal for new or expanded receipt point capacity.
Sempra LNG prefers that the Joint Proposal be adopted. If the FAR proposal and the Joint Proposal are both adopted, Sempra LNG proposes that the scheduling rights provisions and the incremental cost approach of the Joint Proposal be incorporated into the utilities' proposal. This could be accomplished by providing the parties that fund the facilities with a FAR set-aside in Step 1 that is equal to the quantity of the funded capacity.
Kern River Gas Transmission Company (Kern River) is concerned about the current system's regulatory preference in the Northern transmission zone for gas flowing from El Paso and Transwestern. Due to this preference, gas supplies from these two pipelines take precedence over other sources of gas seeking to enter SoCalGas' system from receipt points within the same transmission zone. This preference restricts the ability of SoCalGas' customers from taking lower priced gas supplies from Kern River and Questar Southern Trails Pipeline (Questar) through the Kramer Junction and Needles receipt points in the Northern transmission zone. According to SDG&E and SoCalGas, if the FAR proposal is adopted, this preference would be eliminated. Kern River contends that this preference should be eliminated regardless of whether the FAR proposal is adopted or not.
Some criticize the five cents per Dth per day reservation charge as an arbitrary charge that is either too much or too little, and that it should be eliminated or increased. Some parties criticize the proposed credit back of the reservation charge and contend that this credit mechanism should apply to all the holders of the FAR and not just to end-users.
Coral Energy and the Southern California Generation Coalition (SCGC) contend that the proposed reservation charge is an unlawful charge on interstate shippers that are not being provided with transportation on the SDG&E and SoCalGas system. To the extent that SDG&E and SoCalGas seek to impose an access charge on shippers that are not end-use customers on the system, the access charge is unlawful and must be rejected. They assert that the reservation charge is the same type of charge that the FERC determined in 77 FERC Par. 61,283 (December 19, 1996) was in violation of the Natural Gas Act.24 In that FERC decision, the FERC found that the charge violated the Natural Gas Act because it was a charge to interstate shippers for the act of moving gas over an interstate pipeline and delivering it to SoCalGas rather than a charge for any service performed by SoCal after its receipt of the gas. SCGC contends that the credit back serves to collect the costs of intrastate facilities from interstate shippers who do not transport gas over those facilities. Coral Energy also asserts that the access charge unduly discriminates against upstream suppliers and marketers in violation of Pub. Util. Code § 453(a).
SDG&E and SoCalGas, SCE, and Watson/IP/CCC/CMTA contend that the reservation charge is not unlawful. They contend that the reservation charge in the FAR proposal is distinguishable from the type of charge that was found to be unlawful by the FERC.
Woodside Natural Gas Inc. (Woodside) is concerned that the five cents per Dth charge does not accurately reflect the costs of firm access to all areas of the SoCalGas system from the different receipt points. Woodside contends that the proposed interconnections on the west side of the SoCalGas system require fewer facilities to accept the gas and flow the gas to the load center. For that reason, Woodside contends that the Commission should adopt a system of zonal prices, instead of a postage stamp rate, that reflects the costs of creating firm access from particular receipt points and zones. Woodside contends zonal pricing would encourage the development of the most cost effective source of natural gas supplies for the California market.
Coral Energy contends that the payment of the FAR reservation charge has the effect of reducing flexibility because it discourages a customer or shipper from switching to a different receipt point to take advantage of lower priced gas supplies.
SES Terminal LLC (SES) contends that SDG&E and SoCalGas have not justified the FAR reservation charge, or adequately explained why end-users are the only ones who will receive a credit for the FAR reservation charge, while those who are not end-users, but pay for the charge, will not receive any credit. SES views this credit mechanism as another financial impediment from discouraging or preventing LNG suppliers from accessing the SDG&E and SoCalGas system. If the reservation charge is adopted, SES recommends that the credit also go to the holders of the FAR who are not end-use customers.
Watson/IP/CCC/CMTA and SCGC propose that the FAR revenues be credited back on the basis of average year throughput (equal cents per therm) instead of on a cold-year throughput basis. SCGC contends that the FAR charge has no relationship at all to cold-year throughput.
DRA opposes the 90/10 sharing mechanism for interruptible revenues. Since the FAR proposal does not put shareholders at-risk, DRA contends it is unreasonable for the utilities to share in any reward. In addition, DRA believes that the utilities should be expected to make all interruptible capacity available without the need for a financial incentive.
Several parties oppose the proposal of SDG&E and SoCalGas to collect an in-kind fuel charge from the holders of the FAR. The parties opposed to the charge contend that because transmission costs have not been unbundled and because SoCalGas is not at-risk, the fuel charge should not be unbundled either. Others contend the in-kind fuel charge would shift the cost responsibility from the end-use customer, who they contend should pay the costs associated with transmission-related fuel costs, to the holders of FAR and to the suppliers who are delivering gas to the SDG&E and SoCalGas system. BHP contends that if an in-kind fuel charge is adopted, that LNG shippers should receive a credit for the fuel charge.
(1) Transmission Zones
SES and BHP are concerned with the way in which the transmission zones were designed and how the receipt points were designated. They contend that this provides an advantage to the LNG supplies which enter through Otay Mesa. The other competing LNG supply projects would be in their own transmission zone with a single receipt point.
(2) Step 1
Various parties propose that they receive set-asides in the Step 1 process. Occidental of Elk Hills, Inc. (OEHI) proposes that it be provided with a set-aside of 90 MMcfd for its natural gas production at the Gosford interconnection.25 OEHI contends that a set-aside is justified because it is a California producer, and at SoCalGas' request, invested more than $13 million to construct an outlet for its production at the Gosford interconnection. Without a set-aside, OEHI would not be able to reliably deliver its production to the Gosford interconnection or to another outlet, which could result in a shut in of its oil and gas production.
The "Oxnard 3" propose that they receive a FAR set-aside at Wheeler Ridge using historical demand with adjustments to account for expected load growth as reasonably demonstrated by the customers. 26 Under the FAR proposal, Step 1 provides the Oxnard 3 with a set-aside using the Tier I contract quantities in the Oxnard 3 contracts. Watson/IP/CCC/CMTA27 contend that the proposed set-aside is deficient in two ways. First, the set-aside is limited to Tier I volumes. The Oxnard 3 contracts, however, allow for firm Wheeler Ridge service for both Tier I and Tier II quantities. Second, the proposed reservation charge would require the Oxnard 3 to pay for Wheeler Ridge capacity even if the Oxnard 3 does not use the capacity. The Oxnard 3 contracts only require the Oxnard 3 to pay for the service that they actually use.
SDG&E and SoCalGas do not object to the set-aside being based on the higher of Tier I volumes or the most recent annual average usage. They are, however, concerned with the Oxnard 3's proposal to base the set-aside on "projected maximum daily demand." SDG&E and SoCalGas are also concerned about the Oxnard 3's proposal that they be charged for capacity on a volumetric basis.
PG&E proposes that the holders of PG&E's long-term GX-F contracts for off-system delivery into the SoCalGas system be provided with set-asides at the PG&E Kern River Station receipt point. There are six Commission-approved long-term G-XF contracts with a maximum daily delivery of 86 thousand Dth per day (MDthd) into the SoCalGas territory with Kern River Station as the specified delivery point. Kern River Station delivers into the Wheeler Ridge transmission zone. The largest of the six contracts is for 52 MDthd with SDG&E's core. That contract is already included in the core set-asides that SDG&E and SoCalGas are proposing. The five other contracts have not been allocated a capacity set-aside.
PG&E contends that the five G-XF contract holders should be granted a set-aside. These Commission-approved contracts are long-term contracts with original terms of 30 years and have remaining terms of 8 to 17 years. These five contracts have a maximum daily quantity of 34.5 MDthd, which is less than five percent of the Wheeler Ridge transmission zone capacity. Without a set-aside, PG&E contends it would be very difficult for these contract holders to obtain an exact match for their contracted capacity under the proposed open season.28 Since the contract holders are not end-users, they would not be able to bid until Step 3, when there may be no capacity left.
Exxon Mobil Corporation (Exxon Mobil) contends that if a FAR system is adopted, it should receive a set-aside in Step 1 for its gas production from its Santa Ynez unit that delivers into the Coastal transmission zone. Exxon Mobil contends that its gas production has the same attributes as other California gas production that qualifies for the set-aside.
SCGC proposes that noncore customers who hold long-term commitments to upstream pipeline capacity that deliver into the SDG&E and SoCalGas transmission system should be provided with set-asides. SCGC notes that although most noncore customers do not hold commitments to upstream pipeline capacity, electric generation customers do. SCE agrees with SCGC that electric generation customers should be able to receive set-asides to match their upstream pipeline contracts.
Watson/IP/CCC/CMTA oppose SCGC's proposal for a set-aside for noncore customers who hold interstate pipeline capacity. Watson/IP/CCC/CMTA contend that, in contrast to SoCalGas' long-term transportation contracts that provide contract holders with specific firm receipt point rights, SoCalGas never made a long-term agreement with these noncore customers that they would have firm service for their supplies from interstate pipelines. Watson/IP/CCC/CMTA point out that SCGC has not provided any details on how such a proposed set-aside should work and how the proposed set-aside will affect the remaining capacity to noncore customers.
Watson/IP/CCC/CMTA propose two modifications to the Step 1 process. The first modification is to split the process so that California producers with existing rights to deliver a maximum daily volume (MDV) be allowed to exercise their set-aside rights before those producers with interruptible access agreements. Watson/IP/CCC/CMTA contend that such a modification is warranted because the producers with MDV rights should not have their set-aside rights pro-rated with the set-aside rights of producers with interruptible access agreements, and that it will preserve the benefit of the bargain that the producers had negotiated.
The second modification proposed by Watson/IP/CCC/CMTA is to base the California producer set-aside on an individual producer's peak month production delivered into the SoCalGas system over the most recent three years, instead of the utilities' proposal to base the set-aside on the most recent year of production data. Watson/IP/CCC/CMTA contend that the proposal of SDG&E and SoCalGas may not accurately reflect future peak output. In addition, Watson/IP/CCC/CMTA propose that producers should be allowed to justify a set-aside greater than that indicated by the historical data "if the producer had historical peak-month production that was shut-in or restricted due to operating constraints, or if the producer can show the utility it has obtained permits and ordered equipment that will increase production above historical levels."
SCE is concerned about the length and the term of the core upstream contracts. SCE proposes that the core not receive set-aside rights for upstream contracts that expire during the three year cycle, or alternatively, that the core be precluded from re-contracting the same upstream space if the contract expires during the cycle.
SCE proposes that any capacity acquired as a set-aside for reliability purposes should not be allowed to be re-contracted for capacity at another point. This is to protect against a set-aside from being traded or sold for a marketing opportunity, instead of being used for its intended purpose. SCE would allow the release of the set-aside capacity if the contracted capacity is no longer needed for its intended purpose.
(3) Step 2
Two members of the Indicated Producers, Aera Energy LLC (Aera) and Midway Sunset Cogeneration Company (MSCC) request that as long-term enhanced oil recovery (EOR) contract holders, that they be permitted to acquire FAR under the same terms and conditions as other customers in Step 2 of the open season, and to receive the reservation charge credit against their firm long-term contracts. Although SoCalGas considers these EOR contracts to be interruptible contracts pursuant to D.90-09-089, Aera and MSCC contend that the decision only determined the EOR contracts to be interruptible for the purpose of determining end-use curtailment priority. Aera and MSCC are concerned that if their EOR contracts are treated as interruptible contracts, they may lose their long standing level of receipt point access priority.
SDG&E and SoCalGas contend that these long-term EOR contracts are interruptible contracts under D.90-09-089 and D.04-04-015.29 SDG&E and SoCalGas will permit the holders of these interruptible contracts, such as Aera and MSCC, to bid for FAR in Step 2 if they upgrade their service from interruptible to firm and pay the associated reservation charge.
(4) Step 2 - Maximum Bidding Rights
Several parties expressed concern about how the maximum bidding rights in Step 2 will be derived.
Southwest Gas Corporation (SWG) is concerned that it would only be provided with a base load maximum bidding right based on an historical annual average usage during the base period. SWG contends that if its bidding rights are based on historical annual average usage, it will not have enough bidding rights to secure all of the FAR it needs to serve its core customers during extreme cold weather conditions. In addition, SWG is concerned that if its core demands continue to grow, that this growth will not be adequately reflected in the bidding rights methodology.
SWG recommends that in Step 2, local distribution companies such as SWG, be allocated the bidding rights it needs to serve their core extreme weather demands during the three-year term. SWG also recommends that any remaining existing receipt point capacity in Step 3 have a maximum term of three years instead of the proposed 15 years.
For Step 2, SCGC proposes that the customer's bidding rights be set at the customer's highest usage in each month over the past three years. SCGC contends that such a modification is needed because the load of an electric generation customer can vary from year to year due to weather. The use of this method will provide an electric generation customer with a better opportunity to meet its potential load.
Watson/IP/CCC/CMTA do not believe that SCGC's proposal to use the highest usage in each month reflects typical operations. Instead of adopting SCGC's proposal, Watson/IP/CCC/CMTA propose that the customer be allowed to choose that its annual bidding right be determined on the basis of the annual average of three years of recent historical consumption data, or the existing contract quantity.
SCE proposes that the calculation of the maximum bidding rights in Step 2 be modified to account for the tolling agreements. The tolling agreements require SCE, SDG&E and PG&E to deliver the gas needed to generate electricity to those electric generators who have contracted with the Department of Water Resources (DWR) or with the utility. Due to the way in which the tolling agreements were written, it is unclear whether they would be included as part of the historical usage that the maximum bidding rights are based upon. In addition, under the tolling agreements, the plant owner of the electric generator is considered the end-use customer under the existing gas transportation tariffs, even though it has no role in the purchase or transport of this gas. Under Step 2 of the open season, the end-use customer is considered the plant owner. Since the end-use customer's bidding rights in Step 2 are based on the customer's historical annual throughput, the tolling agreements are not recognized.
In order for these tolling agreements to be considered in Step 2, SCE requests that the Commission direct SDG&E and SoCalGas to assign the Step 2 bidding rights to the electric utility (or applicable load serving entity) with the tolling obligation. SCE recommends that the Commission require that when an end-use customer (i.e., the plant owner of an electric generation facility) has contracted with a third party (i.e., DWR or one of the electric utilities) to supply natural gas for electric generation under the terms of a tolling agreement, that the Step 2 bidding rights be provided to the third party that supplies the natural gas for the electric generation.
SCGC is concerned that the preference in the bidding process for annual base loaded bids over monthly bids is inappropriate because it will result in economic harm to low load factor electric generators. DRA is concerned that the impact of this preference has not been fully examined on these low load factor customers.
Watson/IP/CCC/CMTA contend that the preference for annual bids over seasonal bids is reasonable because the annual bids provide greater economic value to the utilities and maximize the use of system capacity. They contend that if a seasonal bid is given the same priority as an annual bid, that this could force the utilities to pro-rate the annual bids during certain months when the receipt point is full.
(5) Step 2 - Treatment of New Capacity
In the Step 2 process, end-use customers have priority access to existing receipt points. Watson/IP/CCC/CMTA point out that the new receipt points at Otay Mesa and with the North Baja Pipeline at Blythe are not included in the receipt points that are available to end-use customers. Watson/IP/CCC/CMTA contend that both of these new receipt points should be made available to end-use customers in Step 2. Including these two receipt points in the Step 2 process will make 400 MMcfd and 600 MMcfd available at Otay Mesa and North Baja at Blythe, respectively.
Coral Energy opposes the proposal of Watson/IP/CCC/CMTA to have new capacity bid on in Step 2 by end-users only. If this new capacity is on a rolled-in basis, Coral Energy asserts that all market participants should have equal access to the new capacity, including the party who paid to build that capacity. Under the proposal of Watson/IP/CCC/CMTA, the core and noncore customers, by bidding in Step 2 for the new capacity, could limit the amount of capacity Coral Energy could obtain in Step 3.
(6) Step 2 - 75% Limitation on Available Capacity
SCE and SCGC propose that the 75% receipt point capacity limit in Step 2 be eliminated, and that 100% of receipt point capacity be made available in Step 2. SCE points out that the application of the 75% limitation may result in a situation that reduces access to the most popular receipt points in a zone, and gas would have to be obtained at less economic receipt points which raises the price of gas.
Coral Energy, PG&E and Sempra LNG also favor the elimination of the 75% limitation. Sempra LNG proposes that the capacity limitations be based upon historical utilization by month at each individual receipt point, using a five year average (2001 through 2005). Sempra LNG contends that such a change will assure customers and shippers that the firm capacity awarded in Step 1 and Step 2 will reflect the historical patterns relevant to each receipt point, while reducing the uncertainty caused by the 75% limitation.
(7) Step 2 - Length of Contract Term
SCGC proposes that the contract terms for Steps 1 and 2 should be for a two-year term instead of three years. SCGC points out that trying to match a three-year FAR cycle with a two-year G-FT contract will create additional transaction costs. Coral Energy is also concerned about the length of the three year term.
Watson/IP/CCC/CMTA oppose SCGC's proposal for a two-year FAR contract term, and favor a three-year term instead. Watson/IP/CCC/CMTA suggest that the G-FT agreements be extended to three years to match the term of the FAR cycle.
(8) Step 3
In the event the Joint Proposal is not adopted, Sempra LNG recommends that the Step 3 bids by a party or parties that advanced the construction funds for new expansion or displacement capacity receive first priority for firm rights up to the amount of the new capacity. This proposal preserves the principle in the Joint Proposal that the parties who are willing to pay for the cost of new capacity should receive the benefits.
Coral Energy is concerned that the Step 3 process does not take into account that Coral Energy and Sempra LNG already paid for the incremental cost for 400 MMcfd of receipt point capacity at Otay Mesa. Coral Energy contends that those who paid for capacity should not have to compete in the open season bidding process for that capacity.
Clearwater points out that under the FAR proposal, new expansion capacity with rolled-in rate treatment would be made available in all three steps. However, new expansion capacity that has been paid on an incremental basis by a party would only be made available in Step 3. This proposal would allow end-users to receive a set-aside in Step 1 or to bid on the expanded capacity in Step 2 and Step 3. End-users and all other market participants can only bid for expansion capacity that has been paid for on an incremental basis in Step 3. Clearwater proposes that the bidding for all new expansion capacity take place in Step 3 only so that all expansion capacity can be made available to all end-users and other market participants at the same time.
BHP opposes Clearwater's proposal to hold the bidding for all expansion capacity in Step 3. BHP contends that the Clearwater proposal would result in a delay of the funding and commitment for the facilities needed for the expansion capacity until it is known who is awarded the FAR for that capacity.
Some of the parties suggest bifurcating the Step 3 process into two stages. The first stage would allow market participants to bid for existing capacity. The second stage would allow market participants to bid on expansion capacity. The parties contend that bifurcation of the bids for existing and expansion capacity avoids the problem in the FAR proposal of having those who want existing capacity ending up paying for a share of the expansion capacity.
Watson/IP/CCC/CMTA and Woodside are concerned with the Step 3 proposal that a shipper who wants to establish a new receipt point, or to expand an existing interconnection, will have to pay the FAR reservation charge plus the levelized incremental costs for the new receipt capacity. They contend it is unfair to require new suppliers to pay for both the costs of the existing transmission system (collected through the reservation charge) and for the incremental costs to expand the system. Watson/IP/CCC/CMTA recommend that shippers pay the higher of the Commission adopted FAR reservation charge or the 15-year levelized costs for the expansion capacity that is being added. Watson/IP/CCC/CMTA contend that this is more fair because a shipper that adds relatively low cost displacement capacity at a receipt point will pay at least the basic FAR reservation charge for the existing system, while a shipper that adds expensive expansion capacity will pay for the full costs of that capacity over 15 years.30
Some parties contend that the Step 3 process favors Sempra LNG and Coral Energy because they would be allowed to bid for displacement capacity at Otay Mesa and the North Baja receipt points, while LNG projects located at Long Beach or Oxnard would have to pay for more expensive expansion capacity. Clearwater recommends that there be separate bidding in Step 3 for displacement capacity first, and then bidding for expansion capacity.
SES asserts that displacement capacity encourages gas-on-gas competition because the most competitively priced gas will enter the system through the receipt point serving that cheaper priced supply. As a result, for a new supplier to get its gas to the market, it must compete to displace the gas supplies at other receipt points. SES recommends that the construction of receipt point capacity should normally be done on a displacement basis, and that construction on an expansion basis should be the exception. The Commission should therefore adopt a standard that "if the requested establishment or increase in receipt point capacity can be accommodated on a displacement basis without interfering with SoCalGas/SDG&E's ability to provide adequate service to its existing load, then SoCalGas/SDG&E must construct the receipt point on a displacement basis, unless requested by the entity funding the expansion to do otherwise." (Exhibit 40, page 16.) SES contends that the burden must be placed on SoCalGas to justify why the receipt point cannot be built on a displacement basis, and that SDG&E and SoCalGas "should be directed to provide full and complete access for the requesting party to all work papers, models, flow diagrams, computer-based modeling and other information utilized in the determination of the necessary facilities and associated costs." (Exhibit 40, page 17.)31
Although the original position of SDG&E and SoCalGas was to require the other LNG suppliers to bid for expansion capacity, SDG&E and SoCalGas subsequently clarified their earlier position and agreed that all new suppliers should have the option to obtain displacement capacity in those situations where expansion capacity costs even slightly more than displacement capacity.
SCE opposes the change in position that SDG&E and SoCalGas have taken on displacement capacity. SCE opposes the change because displacement expansions diminish the firm and interruptible rights of existing customers and drives out lower priced gas. If the objective is to increase the number of gas supplies so as to reduce gas prices for customers, then an incremental expansion should be used instead of a displacement expansion.
Several parties expressed concern about the length of the 15-year commitment in Step 3. Kern River is concerned that the 15-year commitment in Step 3 for existing receipt point capacity may not be warranted for all situations. Sempra LNG asserts that a longer term may reduce the ability for FAR holders to respond rapidly to changing market conditions. Kern River proposes that there be a term of three years for existing capacity, and that a customer paying for expansion capacity should be able to negotiate the term of the amortization of the capital costs and the length of the commitment. Sempra LNG proposes that bidders in Step 3 be allowed to acquire new capacity for a minimum term of three years, and that longer terms be available in three year increments, with a maximum term of 20 years.
SCE opposes including a right of first refusal, i.e., the right to extend, in the term of the contract. SCE believes that such a provision would diminish flexibility in the market.
(9) Secondary Market
Kern River and SCE propose that price caps be imposed on the secondary market transactions. Kern River contends that there are constrained receipt points on the SoCalGas system, and without a price cap, the FAR on the secondary market could "extract an exorbitant price." (Exhibit 33, page 16.) Kern River also contends that many of the shippers on the interstate pipelines are California end-users with firm transportation contracts, and that the rates under these contracts do not change when the basin differential prices change. As a result, if there is no price cap, California end-users are likely to end up paying significantly more for FAR if no price caps are in place. Kern River also points out that the lack of price caps in the secondary market for capacity on the FERC regulated pipelines during the winter of 2000-2001 contributed to the problems experienced during the energy crisis. Kern River cautions that if the Commission waits until the market becomes dysfunctional, a large amount of damage can result before changes are made.
SCE believes that the Commission should be proactive and put a price cap in place until the market has had a chance to mature and the Commission has been able to evaluate market behavior. SCE recommends a price cap of about 125%, i.e., a maximum price of 6.25 cents per MMcfd.32 SCE also suggests that the name of the acquiring shipper be added to the secondary market information that SDG&E and SoCalGas intend to provide.
Watson/IP/CCC/CMTA note that price caps have not been needed in the secondary market for PG&E's Gas Accord, which the unbundled FAR proposal is modeled after.
(10) Nominations and Scheduling
Kern River and SES expressed concern that limiting alternate nominations to within-the-zone locations reduces the flexibility for FAR holders, and favors the affiliate of SDG&E and SoCalGas in the Southern transmission zone.33 In contrast, the FAR holders at either the Salt Works or Center Road receipt points will not have alternate firm rights in any other receipt point on the system if alternate nominations are limited to within-the-zone. Kern River and SES propose that out-of-zone nominations be allowed at no additional cost, and that such a nomination have a lower priority than any firm nomination or within-the-zone nomination, but before interruptible.
In their rebuttal testimony, Exhibit 16, SDG&E and SoCalGas support the change to allow alternate firm nominations out-of-zone at no additional cost, and that such a nomination be scheduled after the alternate firm nominations within-the-zone. Clearwater supports allowing alternate firm nominations to be made out-of-zone.
In the event the Commission does not adopt the alternate firm rights out-of-zone proposal, SES recommends that FAR holders have priority access to interruptible receipt point capacity, up to the amount of their FAR, at no additional charge.
(11) Additional Wheeler Ridge Capacity
PG&E proposes that the level of firm capacity at the Wheeler Ridge transmission zone be increased. Although the stated firm capacity of the Wheeler Ridge transmission zone is 765 MDthd, the data from SoCalGas' EBB system shows that there is frequently a large amount of capacity above the stated level. PG&E contends that increasing the level of firm capacity will be beneficial because shippers prefer the certainty of firm access. Accordingly, PG&E recommends that SoCalGas create short-term secondary-only FAR at Wheeler Ridge above the 765 MDthd level. PG&E proposes that this short-term FAR be scheduled after the primary FAR. PG&E proposes that these rights be sold on a daily, weekly, or monthly basis.
PG&E notes that SDG&E and SoCalGas propose a workable solution in their rebuttal testimony where they propose to offer short-term FAR for capacity at Wheeler Ridge above 765 MDthd, where in the judgment of SDG&E and SoCalGas, additional capacity can reasonably be expected to be available on a firm basis for shorter periods such as one month. PG&E believes, however, that the better solution is to have these short-term FAR scheduled after the primary FAR, versus SoCalGas' proposal to have these short-term rights treated the same as annual FAR.
(12) Continental Forge Settlement and SCE Settlement34
SES contends that the provision in the Continental Forge settlement, which calls for Sempra LNG to sell and SDG&E and SoCalGas to purchase LNG supplies up to 500 MMcfd at the California border price minus two cents for 20 years, runs completely counter to the argument used by SDG&E and SoCalGas that a system of FAR will create greater gas-on-gas competition by allowing customers and shippers to choose their preferred suppliers.
Coral Energy is concerned that the provisions in the Continental Forge settlement and the SCE settlement that call for the sale of up to 500 MMcfd from Sempra LNG's Energia Costa Azul (ECA) facility to SDG&E and SoCalGas may result in preferential access to the capacity in the Southern transmission zone through set-asides at Otay Mesa and/or Blythe/Ehrenberg, and on the upstream pipelines that will transport the gas from the ECA facility.
Coral Energy is also concerned about the provision in the Continental Forge settlement which calls for the core procurement programs of SDG&E and SoCalGas to be combined. If the two are combined, Coral Energy contends that the combined core portfolios could enjoy enhanced market power in Step 1 and Step 2 of the open season process to the disadvantage of noncore customers and new gas suppliers seeking access at existing receipt points.
Watson/IP/CCC/CMTA contend that the competitive concerns that SES raised could be mitigated if all end-users, not just SDG&E and SoCalGas, are allowed to have access to the Sempra LNG volumes at the same price. Watson/IP/CCC/CMTA contend that no group of end-users should have a set-aside at Otay Mesa or North Baja that allows preferential access to the Sempra LNG volumes at the price specified in the Continental Forge settlement.
Coral Energy is also concerned about the provision in the SCE settlement that market participants be allowed to fund an expansion of a receipt point with limited delivery rights. Coral Energy contends that this provision could allow a customer to construct a lateral expansion to a receipt point to obtain firm access without expanding the receipt point's takeaway capacity and without having to participate in an open season.
The SCE settlement also references the minimum flow requirement. Coral Energy is concerned about how this requirement will work, and notes that the testimony in this proceeding did not address the minimum flow obligation.
(13) Future Review
SCE proposes that the Commission review the FAR system to determine how it is operating, and to determine if it should be continued or eliminated. SCE suggests that this review take place in an application to be filed by SDG&E and SoCalGas no later than 120 days from the end of the second FAR open season.
D. Unbundled FAR Proposal
The unbundled FAR proposal refers to the proposal in Exhibit 43, the testimony of R. Thomas Beach, that Watson/IP/CCC/CMTA are sponsoring. The unbundled FAR proposal is modeled after elements of the FAR proposal and PG&E's Gas Accord market structure. Watson/IP/CCC/CMTA contends that the Gas Accord structure has worked well for PG&E. The unbundled FAR proposal allows the holder of the FAR to move its gas through the receipt point to the citygate.
There are two major differences between the FAR proposal and the unbundled FAR proposal: the unbundling of backbone transmission costs; and putting SDG&E and SoCalGas at-risk for the recovery of the backbone transmission costs.
The first difference is the unbundling of $157.3 million in annual backbone transmission costs that were allocated to noncore customers in the system integration decision, D.06-04-033. Under the unbundled FAR proposal, these transmission costs would be recovered through the 15.75 cents per Dth per day FAR reservation charge, instead of the five cents per Dth reservation charge under the utilities' FAR proposal. According to Beach, the 15.75 cents per Dth "provide a reasonable measure of the costs of backbone transmission on the SoCalGas/SDG&E system." (Exhibit 43, page 32.) In contrast to the utilities' FAR proposal, the 15.75 cents per Dth reservation charge would not be credited back to end-users under the unbundled FAR proposal because that rate recovers the unbundled backbone transmission costs. Since the 15.75 cents reservation charge is based on the transmission component of the rates adopted in D.06-04-033, Watson/IP/CCC/CMTA contend there is no need at this time for a cost study to unbundle rates.
Watson/IP/CCC/CMTA contend that the 15.75 cents reservation charge provides better market-based signals. The higher FAR reservation charge will create a more robust citygate market by allowing and encouraging greater competitive savings in the market. Watson/IP/CCC/CMTA also point out that the unbundled FAR proposal is fair to all customers because they are all charged the same 15.75 cents per Dth rate and no credit back is needed.35
The second major difference between the unbundled FAR proposal and the utilities' FAR proposal is that Watson/IP/CCC/CMTA would put SDG&E and SoCalGas 100% at-risk for the recovery of the unbundled noncore transmission costs. Watson/IP/CCC/CMTA assert that placing SDG&E and SoCalGas at-risk is consistent with the at-risk provisions in PG&E's Gas Accord structure. It will also provide SDG&E and SoCalGas with the incentive to expand their services to new markets, and will provide the utilities with an incentive to keep their rates competitive with competing suppliers.
Watson/IP/CCC/CMTA support balancing account protection for the core transmission costs. They contend that the balancing account protection for the core will ensure "the utilities do not have an incentive to increase core loads that conflicts with utility-administered energy efficiency programs for the core." (Exhibit 43, page 33.)
Since the FAR reservation charge does not depend on the amount of throughput, as opposed to the utilities' current all-volumetric rate structure, Watson/IP/CCC/CMTA contend that this change in rate design will mitigate the utilities' risk of under-recovering their noncore transmission costs.
Watson/IP/CCC/CMTA propose that the maximum rate for interruptible access be set at 120% of the firm reservation charge. Setting the interruptible charge at a 20% premium will give shippers a strong incentive to contract for firm service, which should further aid in mitigating the risk of under-recovering the noncore transmission costs.
SDG&E and SoCalGas are opposed to the unbundled FAR proposal because of the at-risk provision and the unbundling of costs.
SDG&E and SoCalGas criticize the at-risk provision because it would create disincentives for encouraging energy efficiency and conservation efforts, and discourage them from constructing additional slack capacity on the backbone transmission system. Due to the at-risk provision, SDG&E and SoCalGas contend that this will provide them with the incentive to maximize their throughput, i.e., to ensure that as much gas as possible is transported through the backbone transmission system, in order to make sure that they can recover their noncore backbone transmission costs. SDG&E and SoCalGas contend that such an incentive is contrary to the energy efficiency and conservation goals.
The at-risk provision would also discourage SDG&E and SoCalGas from constructing additional slack capacity. This is because once the backbone transmission costs and the base load factor are determined, SDG&E and SoCalGas have the financial incentive to increase the actual load factor by increasing throughput, while ensuring that the backbone transmission costs do not increase.
SDG&E and SoCalGas point out that arriving at a base load factor for purposes of determining the at-risk rate structure is also a highly contentious issue.
SDG&E, SoCalGas, and The Utility Reform Network (TURN) are concerned about the unbundling aspect of the unbundled FAR proposal. The unbundling of backbone transmission costs from transportation rates could result in cost shifts to smaller customers. One possible result of unbundling transmission costs is that this could lead to a backbone-only rate that would allow a customer directly connecting to the backbone transmission system to avoid making a contribution to the fixed costs of the local transmission and distribution system. A backbone-only rate would result in a shift of the fixed costs of the local transmission and distribution costs onto the remaining customers that rely on these parts of the system, primarily the smaller noncore customers and core customers. SDG&E and SoCalGas recommend that if the Commission decides to adopt the unbundling of backbone transmission costs from transportation rates, the Commission should make clear that it does not intend to adopt a backbone-only rate.
SCGC also expressed concern that the unbundled FAR proposal would shift recovery of the backbone transmission costs from on system transportation customers of SDG&E and SoCalGas to the upstream entities that hold the FAR. Through the unbundling of transmission costs, SCGC believes that the industrial customers will purchase their gas supplies at the citygate, thereby avoiding having to pay the backbone transmission cost. The upstream entities and on-system customers, such as electric generators, who need to hold FAR, would end up paying all of the unbundled transmission costs. SCGC further contends that since this proceeding is not the BCAP, this proceeding should be neutral on how the costs should be allocated among customers and customer classes.
Several parties oppose the unbundled FAR proposal because of the 15.75 cents per Dthd charge that Watson/IP/CCC/CMTA recommend be adopted. These parties contend that the 15.75 cents is excessive, that it will discourage parties from holding FAR, that the gas shippers will bear the costs of backbone transmission, and that the rate will create a significant barrier to the entry of new supplies.
SCGC is concerned that no cost studies were performed in conjunction with the unbundling aspect of the unbundled FAR proposal. SCGC contends that there is no support for deriving the cost of the backbone transmission and the cost of local transmission and distribution.
In the event the Commission decides to unbundle backbone transmission costs from the transportation rate, SDG&E and SoCalGas recommend that this be done without adopting the at-risk provision so that the adopted FAR system does not conflict with the energy efficiency and conservation goals. In addition, if rates are unbundled and the at-risk provision is not adopted, a separate "Backbone Balancing Account" would have to be established to track the undercollection or overcollection of the backbone transmission costs.
The parties who oppose the unbundled FAR proposal also contend that it has many of the same flaws as the FAR proposal. That is, the unbundled FAR proposal reduces customer flexibility, it may lead to increased gas costs, hoarding of capacity, market manipulation, and a reduction in the value of the interstate pipeline capacity that end-users hold. For the same reasons mentioned with respect to the FAR proposal, the 15.75 cents per Dth reservation charge in the unbundled FAR proposal would also be unlawful.
E. Division of Ratepayer Advocates' Proposal
The DRA supports the retention of the current market structure for SoCalGas and SDG&E. In the event the Commission wants to establish a system of FAR for SDG&E and SoCalGas, DRA recommends the Commission do so by directly allocating FAR to end-use customers based on the current allocation of intrastate gas transmission costs in the last BCAP, D.00-04-060. DRA proposes that the allocation process exclude the California gas production receipt points in order to simplify the allocation process. DRA estimates that SoCalGas' transmission costs are allocated 42% to the core and 58% to the noncore. Under DRA's proposal, the core would be allocated 1,455 MMcfd, and the noncore would be allocated 2,010 MMcfd.
DRA proposes that core customers be allowed to match their current interstate rights if the allocation based on the BCAP cost allocation would result in a mismatch at a given receipt point, in exchange for fewer rights at another receipt point. Under DRA's proposal, customers would be able to trade and assign their rights, and the term for the allocation of the FAR could range from one to three years.
DRA contends that allocating FAR on the basis of cost responsibility is fair because the allocation is based on the customers' share of the transmission costs. Compared to the current system, DRA acknowledges its proposal is less flexible. However, as compared to the FAR proposal and the unbundled FAR proposal, DRA contends that its allocation proposal has the following advantages: it is simpler; it does not impose additional costs on customers and does not increase the cost of delivered gas; no additional costs are needed to prevent hoarding or market manipulation; the value of the FAR benefits those customers who are paying the costs; and it avoids the legal issues concerning the imposition of an access charge.
With respect to the $10 million in displacement expansion capacity that is to be built at Otay Mesa, DRA recommends that the 400 MMcfd of displacement capacity at Otay Mesa be rolled-in and allocated to ratepayers. DRA contends that this per unit cost of expansion for the first 400 MMcfd is much cheaper (2.5 cents per cubic feet per day) than the next 300 MMcfd of displacement capacity (78 cents per cubic feet per day).
SDG&E and SoCalGas oppose DRA's capacity allocation proposal. They contend that DRA's proposal does not permit customers to choose the receipt points they desire, and does not provide them with the flexibility to match their capacity with their upstream contract rights. SCE notes that under DRA's proposal, all customers would receive some capacity at every receipt point. SDG&E and SoCalGas, as well as SCE, state that DRA's proposal is likely to require significant secondary market transactions after the allocation process to match capacity with supply. SDG&E and SoCalGas also point out that DRA's proposed allocation method fails to provide non-end-use customers, such as suppliers and marketers, with an opportunity to acquire FAR so that they can deliver their supplies into the system. Also, DRA's allocation of 100% of the capacity does not provide for any displacement expansion capacity for LNG supplies.
TURN and Sempra LNG oppose DRA's proposal to roll-in the 400 MMcfd of displacement expansion capacity at Otay Mesa, while Clearwater supports DRA's roll-in proposal. TURN contends that the Otay Mesa displacement capacity should be paid for on an incremental basis. Sempra LNG contends that there should be a set-aside in Step 1 for whoever paid for the new receipt capacity.
F. Joint Proposal
The Joint Proposal establishes a process for expanding receipt point capacity on the SDG&E and SoCalGas transmission system. A copy of the Joint Proposal is attached to Exhibit 85. The Joint Proposal is sponsored by the following parties: BHP, Coral Energy, SES, Sempra LNG, SCGC, TURN and Woodside.
The Joint Proposal focuses on four topics pertaining to new or expanded receipt point capacity. The first topic is that the parties that either construct and surrender or advance the incremental cost for new or expanded receipt point capacity would be granted a "scheduling right" in the amount of the receipt point capacity for 20 years. The second topic is the protocol for determining whether the new or expanded capacity is to be on a displacement or expansion capacity basis. The third topic provides for optional funding methods for creditworthy entities to construct and surrender or finance the construction of new or expanded receipt point capacity. The fourth topic of the Joint Proposal addresses specific protocols for granting scheduling rights for new or expanded receipt point capacity in the Southern transmission zone.
The Joint Proposal states that it is a stand-alone proposal that is to operate independently of whether a system of FAR is adopted or not. The Joint Proposal further provides that if a system of FAR is adopted together with the Joint Proposal, the scheduling rights in the Joint Proposal shall not be diminished by the FAR system.
The scheduling right is defined in the Joint Proposal as follows:
If a Funding Party either constructs and surrenders, or advances the incremental costs of facilities that add Displacement Capacity or Expansion Capacity on the SoCalGas/SDG&E system, the Funding Party shall acquire a `Scheduling Right.' A Scheduling Right is the right to schedule the use of Displacement Capacity or Expansion Capacity on a firm basis from a receipt point on the SoCalGas/SDG&E system. The nature of the Scheduling Right that is acquired by a Funding Party depends upon whether the takeaway capacity that is established or increased at a particular receipt point is Displacement Capacity or Expansion Capacity. The Scheduling Right shall be transferable. (Exhibit 85, Exhibit A, pages 3-4.)
The scheduling right that a funding party will receive depends on whether the increased receipt point capacity reflects expansion capacity or displacement capacity. If the capacity is done on an expansion capacity basis, "the Funding Party shall have the right each day to nominate and schedule a volume of gas for delivery into the SoCalGas/SDG&E transmission system at that receipt point on a firm basis in an amount up to at least the amount of the Expansion Capacity for which the Funding Party advanced the cost." (Exhibit 85, Exhibit A, page 6.) The scheduling right for an expansion capacity is not subject to reduction from nominations by shippers at other receipt points within the same transmission zone.
If the capacity is done on a displacement capacity basis, the Joint Proposal provides:
The Funding Party shall have the right each day to nominate and schedule a volume of gas for delivery into the SoCalGas/SDG&E transmission system on a firm basis at that receipt point in an amount up to at least the amount of the Displacement Capacity for which the Funding Party constructed the facilities or advanced the cost, subject to reduction only to accommodate, on a nondiscriminatory basis (but subject to Paragraph 7 below), nominations at other receipt points in the same Transmission Zone and to accommodate force majeure, scheduled maintenance, or unscheduled maintenance situations as defined in SoCalGas Rules 1 and 23. (Exhibit 85, Exhibit A, pages 6-7.)
The scheduling right for displacement capacity is subject to reduction to accommodate nominations at other receipt points in the same transmission zone.
The term of the scheduling right is to be for the lesser of the term of the contract or 20 years. At the end of the term, the funding party may renew its scheduling right for the same or shorter term. The scheduling right would be transferable.
The second topic of the Joint Proposal addresses the protocol for determining whether the capacity should be built on an expansion capacity or displacement capacity basis. The protocol provides that upon an entity's request to establish or increase takeaway capacity from a receipt point, SDG&E or SoCalGas is to make a timely determination of the facilities, facility modifications, and associated costs that are required to add the takeaway capacity on both a displacement capacity and expansion capacity basis. The protocol also provides that the utility is to provide the requesting entity with access to all cost and engineering information used in the determination, subject to an agreed upon protective order if one is requested by the utility or the requesting entity. Based upon the facility and cost information and any physical system limitations reflected in that information, the Joint Proposal provides that the funding party "shall be permitted" to decide if the capacity should be funded on a displacement capacity or expansion capacity basis.
The third topic of the Joint Proposal describes three funding options for how a funding party may choose to pay for the facilities. The first option is for the party to construct the necessary facilities up to the interconnection with the utility's current facilities and to transfer ownership and operating responsibilities to SoCalGas or SDG&E, without further charges for the transferred facilities.36 The second option is for the party to contribute the costs of the necessary facilities to the utility without refund or repayment and without ongoing charges for the facilities. The third option is for the party to advance the funds to the utility in accordance with an executed Collectible System Upgrade Agreement (CSUA), in which case the funding party is to receive a refund of the advanced funds when the gas first flows through the receipt point, subject to the party entering into a contract with the utility that obligates the funding party to pay "a monthly facilities charge that is equal to the utility's revenue requirement for the capitalized construction costs based on amortization of the construction costs over the term of the contract and the utility's authorized rate of return, including depreciation, taxes, and fees." (Exhibit 85, Exhibit A, page 5.)
The fourth topic of the Joint Proposal describes the scheduling rights for receipt point capacity additions in the Southern transmission zone that are done on a displacement capacity basis. The Joint Proposal provides that incremental cost allocation shall apply to the first 700 MMcfd of displacement capacity at the Otay Mesa receipt point, and that rolled-in cost allocation treatment will not be adopted for this amount of displacement capacity. The Joint Proposal further provides that any funding party that advanced the costs of establishing and/or increasing the Otay Mesa receipt point capacity to an amount of displacement capacity of at least 400 MMcfd is to receive a scheduling right at the Otay Mesa receipt point.37 If a party funds additional displacement capacity at Otay Mesa above the 400 MMcfd, up to 700 MMcfd, that party will receive a scheduling right at the Otay Mesa receipt point, but will not diminish the scheduling right held by any funding party that previously obtained a scheduling right at the Otay Mesa receipt point.
Due to the addition of displacement capacity at the Otay Mesa receipt point, the Joint Proposal provides that the scheduling rights at Otay Mesa are subject to the following two scheduling provisions. First, if the cycle 1 scheduled flows into SoCalGas' Southern transmission zone exceeds the total zone capacity, SDG&E and SoCalGas will adjust the available takeaway capacity from each of the Southern transmission zone receipt points on a pro rata basis in subsequent nomination cycles, subject to honoring the scheduling rights at each receipt point, and subject to the second scheduling provision. The second scheduling provision provides that the pro rata reduction of nominations shall be adjusted, if necessary, so as not to affect the nominations of SoCalGas' Gas Acquisition Department at Blythe/Ehrenberg, up to the minimum flow requirement, for as long as the Gas Acquisition Department is responsible for meeting SoCalGas' Southern transmission zone minimum flow requirement.
SDG&E and SoCalGas point out that the Joint Proposal does not modify the current system of allocating capacity, and does not modify the current scheduling procedures in the Northern transmission zone or the Wheeler Ridge transmission zone.38 The existing scheduling problems will still remain if the Joint Proposal is adopted by itself.
The Joint Proposal contains a provision that if the Southern transmission zone receives nominations in excess of the firm takeaway capacity, that the nominations will be reduced on a pro rata basis. SDG&E and SoCalGas contend that if this zone is flooded with new supplies from LNG from Baja California, and LNG supplies from the gulf coast, there could be significant pro rata reductions in the zone if the Joint Proposal is adopted.
SDG&E and SoCalGas also contend that if the Joint Proposal is adopted by itself, that the core may not be able to use all of its firm interstate pipeline capacity on the El Paso system because of pro rata reductions that can take place if scheduled nominations are greater than the total zone capacity. In addition, due to the timing of the cycling process and the ability to react and move gas elsewhere, together with possible pro rata reductions in the Southern transmission zone, will create uncertainty for parties as to whether their gas will flow.
SDG&E and SoCalGas also contend that the optional funding provision that states LNG developers may build the facilities for providing access to their supplies and then turn those facilities over to SDG&E and SoCalGas is not needed. If the Commission believes that such a provision is necessary, the utilities request the Commission state in this decision that the facility design and construction must meet utility standards, the utility must monitor the actual construction, and the LNG developer must pay the utility the gross-up for contributions in aid of construction to cover the taxes owed by the utility on such contributions. Also, the Commission needs to address how the ongoing O&M costs of these takeaway facilities will be collected.
SDG&E and SoCalGas also expressed security concerns about the Joint Proposal's requirement that they be required to provide access to the various information, data, and models used by the utilities to determine the facilities that are needed to accommodate new supplies. SDG&E and SoCalGas currently provide access to this information at their offices, and are concerned about others obtaining copies of these kinds of materials.
SDG&E and SoCalGas point out that the Joint Proposal provides that the Joint Proposal can be implemented together with a system of FAR so long as the Scheduling Rights contained in the Joint Proposal are maintained. If both are adopted, SDG&E and SoCalGas propose how the two can be reconciled. To accommodate the provision in the Joint Proposal that scheduling rights be granted to those who fund facility enhancements, a FAR set-aside in Step 1 could be created that is equal to the quantity of funded capacity. By providing the set-aside at a particular receipt point and a particular zone, the issue of how the scheduling rights would operate becomes moot.
SCE opposes the Joint Proposal because it is unnecessary and inferior to the FAR proposal. It is unnecessary because the open season of the FAR proposal already contains a process for the expansion of receipt point capacity that is superior to the Joint Proposal. The Joint Proposal is only intended to provide firm access for LNG providers, which does not create a level playing field. SCE contends that the certainty of firm access should be provided to everyone. SCE asserts that the FAR proposal is superior to the Joint Proposal because it is more inclusive, fairer, and more objective than the first-come, first-served approach.
SCE also contends that the FAR proposal places a limit on displacement expansions while the Joint Proposal does not. If unlimited displacement expansions are permitted, other gas supplies will be displaced that can result in higher gas prices. Incremental expansions, on the other hand, would increase the receipt point capacity and the takeaway capacity of the transmission zone. SCE believes that the Commission should review and assess the potential impact of any additional proposed displacement expansions before allowing them to proceed.
Under the Joint Proposal, the first party that either funds or constructs the new facilities would be given the scheduling right. The FAR proposal, on the other hand, would allocate new or expanded receipt point capacity in Step 3 of the open season. SCE contends that under the first-come, first-served approach, the developers that are further along in the application process would have an advantage over the other projects. Although this encourages early entry into the market, it discourages later developers because of the higher costs of subsequent expansions. SCE also contends that it is uncertain when scheduling rights actually vest, and what first-come, first-served means.
Clearwater opposes the adoption of the Joint Proposal. Clearwater contends that the Joint Proposal lacks the following details: how the scheduling rights will be allocated among the competing parties; what is needed for scheduling rights to vest; and how the scheduling rights can be transferred.
Watson/IP/CCC/CMTA oppose the adoption of the Joint Proposal. They contend that the Joint Proposal results in an unwarranted give-away to Coral Energy and Sempra LNG of the FAR at Otay Mesa for a price that is far below cost. Watson/IP/CCC/CMTA assert that their calculation shows that Coral Energy and Sempra LNG will pay less than one cent per Dth for this receipt point capacity over the next 20 years. This cost is far below the five cents per Dth FAR rate that SDG&E and SoCalGas proposed and the 15.75 cents per Dth rate that Watson/IP/CCC/CMTA proposed.
Watson/IP/CCC/CMTA contend that the cost is so low because ratepayers are already paying for the $100 million that it cost to construct the pipeline to flow gas from SDG&E into Baja California through Otay Mesa in the 1990s as part of the "Pipeline 2000" project. Watson/IP/CCC/CMTA contend that due to the Pipeline 2000 construction, the costs of which are already in rates, the LNG from Sempra LNG's ECA facility will be able to flow from south to north through the Otay Mesa receipt point into southern California. Watson/IP/CCC/CMTA contend it is unfair for Coral Energy and Sempra LNG to receive 400 MMcfd of receipt capacity at Otay Mesa when the ratepayers paid for the facilities that are needed to access this supply.
Due to the manner in which the Otay Mesa receipt point and associated pipelines were developed, Watson/IP/CCC/CMTA recommend that Otay Mesa should be treated as an existing receipt point by rolling in the costs of the 400 MMcfd of capacity. 300 MMcfd, which is 75% of the 400 MMcfd, should be available to end-use customers in Step 2, and the remaining 100 MMcfd should be made available in Step 3. The capacity from North Baja should also be made available in the same manner.
SDG&E and SoCalGas propose that if the costs of the Otay Mesa and North Baja receipt points are not rolled-in, that they be included in Step 3 since these receipt points are intended to deliver new supplies to the system, and because the Otay Mesa receipt point involves the construction of new facilities which, under D.04-09-022, is presumed to require incremental ratemaking treatment.
DRA supports having ratepayers fund the $10 million cost of reversing the flow at Otay Mesa, and that this low cost displacement capacity at Otay Mesa be allocated to the ratepayers. DRA believes that the $10 million cost is a cost effective investment that will provide value to all end-use customers. For that reason, DRA opposes Paragraphs 7.a and 7.b of the Joint Proposal. If these paragraphs of the Joint Proposal are adopted, that would secure firm rights to this 400 MMcfd capacity. DRA states that "Allowing developers to cherry-pick the most inexpensive displacement capacity expansion with incremental cost allocation ratemaking and providing these shippers significant firm rights is not in the end-users best interest." (Exhibit 51, page 2.)
DRA supports granting priority scheduling rights to LNG suppliers, shippers, developers and other interested parties who advance the funds on an incremental cost basis to undertake an expansion capacity of the system. For a displacement expansion, DRA proposes that the funding party be provided with firm access at the receipt point but in the event of a transmission zone constraint, such rights would be subject to reduction.
TURN does not take a position on the proposals for FAR, but if a FAR system is adopted, it should be tailored so as not to undermine the terms of the Joint Proposal. If a system of FAR and the Joint Proposal are both adopted, and a conflict arises between the two, TURN contends the Joint Proposal should control.
G. Discussion
In this Discussion section we provide our reasoning and analysis for adopting a system of FAR as the new gas market structure for SDG&E and SoCalGas. We analyze and compare the current system to the competing proposals. We select the FAR proposal of the utilities as the model for the FAR system, and describe why certain elements of the unbundled FAR proposal and the Joint Proposal have been incorporated into the FAR system. The adopted FAR system also incorporates some of the modifications that the parties proposed to the FAR proposal.
The question that we need to ask ourselves at the outset is whether we should change the existing market structure for southern California now or whether we should we wait to see how the future develops. We have reached this juncture once before. In a span of nine years, we have essentially come full circle, starting with R.98-01-011, the Gas Accord structure as a promising option for SoCalGas, and the adoption and then stay of the CSA. SDG&E and SoCalGas then filed this application, where we are revisiting many of the same issues that we considered when we decided to adopt the CSA. As summarized in the preceding sections, the various parties continue to disagree on what kind of market structure is best for southern California.
We firmly believe that should we postpone a decision on whether a system of FAR should be adopted for SDG&E and SoCalGas, we are likely to be in the same position again in a couple of years trying to resolve the same problems and issues that we have been struggling with for the last nine years. The time is ripe to adopt a system of FAR for southern California.
We have already adopted a system of FAR for PG&E through the Gas Accord and related decisions. The Gas Accord structure has been in existence for PG&E since 1998. Although the parties are correct in noting the differences between PG&E's and SDG&E and SoCalGas' transmission systems, and the differences between the Gas Accord market structure and the proposals that are before us today, the basic underlying system of firm tradable transmission rights has worked and functioned well in northern California. As we stated in D.03-12-061 at page 32:
The evidence shows that the Gas Accord structure has resulted in many gas procurement options and strategies for core and noncore customers, and for gas marketers. Market participants can arrange to purchase gas supplies at the gas basins, and have their supplies transported over interstate and intrastate pipelines to the citygate or to the end-user. Or they can choose to purchase supplies at the border, and have the supplies delivered over the intrastate system, or they can choose to purchase their gas supplies at the citygate. The unbundled, firm tradable capacity rights has created a secondary market which allows market participants to sell or trade their rights to maximize their gas procurement strategies.
In prior decisions, we specifically addressed how a system of firm tradable rights could be beneficial for SoCalGas and SDG&E. In suspending the implementation of the CSA, we stated in D.04-04-015 that "we fully support a market structure that includes firm tradable rights." (D.04-04-015, page 56.) In adopting the CSA, we recognized that the CSA "will provide significant benefits to all utility customers by allowing customers access to firm tradable transmission rights on SoCalGas' system." (D.01-12-018, page 2.) While formulating the most promising options for reforming the gas industry, we recognized that the Gas Accord's creation of tradable access rights to transmission, and the development of a secondary market for those rights, should be examined for SoCalGas' service territory. (D.99-07-015, pages 3, 14.) Based on our past review of the functioning of the Gas Accord structure for PG&E, we continue to believe that a system of FAR will be of benefit to the southern California market as well.
Our decision to adopt a system of FAR for SoCalGas and SDG&E does not hinge solely on the basis that the Gas Accord is functioning well for PG&E, or that we approved the CSA in a prior decision. Instead, as we discuss below, there are other reasons why a system of FAR should be adopted for SDG&E and SoCalGas.
The current system of customers' access to SDG&E and SoCalGas' transmission system can be improved. An analysis of the current system helps illustrate why.
As Watson/IP/CCC/CMTA point out, the circumstances giving rise to the adoption of the CSA are not that much different from what we are faced with today in the southern California market. In the most promising options decision, we were concerned about improving access to SoCalGas' transmission system by potential shippers. (See D.99-07-015, pages 10-14.) In this proceeding, the LNG project sponsors, as well as others, seek assurance that their gas can be delivered. The question that needs to be answered is how can we best provide market participants with this assurance.
No one disputes that under SoCalGas' current system of capacity allocation that all transmission is on an interruptible basis. The issue of whether or not an end-user on the SoCalGas system can transport its gas depends on the upstream shipper's rights, and on system constraints. If the nomination for gas at a popular receipt point exceeds the capacity of the receipt point, capacity constraints will result. Although capacity constraints have not been much of a problem during the past couple of years, that does not mean these constraint problems have gone away.
As all of the parties recognize, constraints at receipt points have been a problem in the past. Some of the parties contend that these constraints will decline over time because of possible changes in gas flows. Others suggest that there is no need for a system of FAR because most of the time, an upstream shipper seeking to deliver gas into the SDG&E and SoCalGas system is able to schedule the full amount that it nominates. However, with the possibility of LNG supplies flowing into southern California, and other changes in the gas market, receipt point constraints may occur again at other receipt points.
Some of the parties contend that the current system offers flexibility, and that this flexibility can be used at other receipt points should a constraint at a particular receipt point occur. However, as pointed out by several of the parties, the flexibility to move to another receipt point is not always available during times of high demand on the system. As a result, under the current system, end-users face uncertainty over whether their gas will flow through the constrained receipt point. Instead of SoCalGas' end-users determining whose gas flows, the upstream pipelines make the decision as to whose gas can flow through the constrained receipt points.
One solution for resolving these constraints at the various receipt points is to build sufficient takeaway capacity on the backbone transmission system. However, no one in this proceeding has proposed that. As several parties point out, the cost of expanding the takeaway capacity would be a very expensive and inefficient solution. The transmission system already has slack capacity, and expanding system capacity to meet infrequent peaks in demand is not a cost-effective solution.
Unless there is more takeaway capacity, capacity allocation is necessary because of the mismatch between the takeaway capacity and the deliverability of the upstream pipelines.
The uncertainty over whose gas will flow also affects the procurement decisions of end-users. Due to possible interruptions in the flow of gas, end-users may be reluctant to enter into longer term contracts, and gas suppliers may have to use higher priced gas if receipt point constraints occur.
We can continue to operate under the current system and wait to see if receipt point constraint problems surface again, or we can take proactive steps to provide market participants with assurances that they can access the SDG&E and SoCalGas transmission systems on a firm basis, and that market participants' nominated gas will flow on any given day. Due to the anticipated changes in gas flows, the likelihood that additional gas supplies will flow into California, and the constraint problems that have occurred in the past and which can reoccur again under the existing market structure, we believe that the current system should be replaced by a system of FAR.
As discussed below, the system of FAR we adopt is based on the utilities' FAR proposal, elements of the unbundled FAR proposal and the Joint Proposal, and certain modifications to the FAR proposal.
Since the current system does not offer assurance to end-users that their gas will flow during times of constraint, the FAR proposal, the unbundled FAR proposal, DRA's proposal, and the Joint Proposal should be reviewed as possible solutions to providing market participants with assurance that they can access the transmission system of SDG&E and SoCalGas on a firm basis. As Sempra LNG noted, the "manner in which access rights are granted to the SoCalGas/SDG&E systems will determine the attractiveness of the California market to upstream suppliers." (Exhibit 108, page 4.)
We first examine DRA's alternative proposal. If a system of FAR is to be adopted, DRA proposes that the transmission capacity be allocated on the basis of how the transmission costs were allocated in the last BCAP. Under DRA's allocation method, core customers would first be allocated sufficient receipt point capacity to match their upstream commitments, with the difference allocated on a proportional basis at each receipt point. The remaining capacity would then be allocated to noncore customers on a pro rata basis in proportion to their individual average demand over the last three years.
DRA's proposed allocation method does not provide shippers and marketers with any firm capacity. Instead, shippers and marketers would either have to procure firm capacity on the secondary market, or have the end-use customer assign their capacity rights to them. Such a system is likely to result in a lot of trading in the secondary market so that shippers and marketers can obtain the firm capacity that they need to transport their gas. DRA's method is also likely to lead to confusion by those noncore end-use customers who receive allocations of firm capacity but are not familiar with what to do with that capacity.
Although DRA's allocation method is simple, we do not believe that DRA's proposal provides all the market participants with what they need or want. Due to the manner in which the firm capacity is allocated, the core and noncore are likely to end up with receipt point capacity that does not match their needs. Under DRA's proposal, market participants are going to spend a lot of time trying to match their needs. Therefore, DRA's proposal is not a practical solution for allocating capacity to market participants and should not be adopted.
The next proposal that we examine is the Joint Proposal.
The Joint Proposal is limited to creating scheduling rights for new or expanded receipt point capacity. It does not establish a system of FAR for the existing receipt points.
As mentioned earlier, we believe that a system of FAR should be adopted to remedy the problem of constrained receipt points. Although the Joint Proposal addresses how the new receipt point at Otay Mesa will interact when the scheduled flows into the Southern transmission zone exceed the capacity of that zone, it fails to address the allocation of capacity at other receipt points on the system.
The premise of the Joint Proposal is that a firm scheduling right to capacity is created for new or expanded receipt points that are built on a displacement capacity or expansion capacity basis, and paid for by a funding party. Inherent in the premise of the Joint Proposal is the recognition of the need for firm rights to capacity when the receipt point has been paid for by the funding party. This suggests to us that instead of limiting capacity rights to new or expanded receipt points, that all receipt points, which have been paid for in rates, should be allocated capacity rights. Instead of adopting a proposal that establishes firm scheduling rights for capacity for only new or expanded receipt points, we should look toward a system of FAR that allows equal access to all market participants at all receipt points.
The above analysis, however, does not preclude us from adopting the Joint Proposal in conjunction with a system of FAR, or adapting elements of the Joint Proposal into our system of FAR. The Joint Proposal specifically provides that it can be adopted on a standalone basis. If the Joint Proposal is adopted with a system of FAR, the Joint Proposal provides that the terms of the Joint Proposal would override the terms of the FAR system.
The Joint Proposal is supported by all but one of the LNG project sponsors, by a gas marketer (Coral Energy), a coalition of electric generators (SCGC), and by a consumer group representing core interests (TURN). A review of the Joint Proposal, and the positions of the supporters, reveals why they support the Joint Proposal. For the LNG project sponsors and Coral Energy, they are assured under the Joint Proposal that if they fund the cost to construct facilities to bring their gas supplies to the receipt points in southern California that they will receive a firm scheduling right to move their gas onto the gas transmission system. The main attraction of the Joint Proposal for SCGC and TURN is that gas supplies at Otay Mesa will be made available, and the cost of the facility, up to 700 MMcfd, will not be rolled into the rates of the customers they represent.
The Joint Proposal is attractive to us for two reasons. First, the creation of a firm scheduling right for new or expanded capacity will provide assurances to gas suppliers and marketers that if they pay for the facilities on an incremental cost basis, that they will be able to move all (expansion capacity) or a substantial portion (displacement capacity) of their gas onto the SDG&E and SoCalGas transmission system. In order to obtain this scheduling right, the funding party must be willing to pay for this new or expanded capacity on an incremental cost basis. By doing so, ratepayers receive assurance that they are not burdened with the cost of the new facilities. The funding of the new or expanded capacity on an incremental cost basis is consistent with our policy that "presumes LNG suppliers will pay the actual system infrastructure costs associated with their projects." (D.04-09-022, page 66.)
We recognize that this scheduling right may impact gas supply projects where two or more project sponsors seek to deliver the gas through the same receipt point. The project sponsor whose project is first in line would obtain a firm scheduling right to move its gas, which may discourage or make it more expensive for the second project sponsor to proceed with its project. 39
We addressed a similar argument concerning how the costs of a receipt point expansion should be allocated in D.06-09-039. We stated that a "first-in-time cost allocation is a crude and, in some ways, unfair approach," but rejected the approach of soliciting interest in a capacity expansion and then allocating the costs equally among the interested parties. We stated that such an approach "could discourage investment," and that incremental expansion costs should be taken into account when siting facilities. (D.06-09-039, pages 76-80, 168-169, 174, FOF 38-39, 41, COL 14.) We are concerned that if a first-in-time approach is not used that investment may be discouraged because a project sponsor may have to delay its schedule on account of a project that is second in line. The delay may cause the first project sponsor to look elsewhere to make its investment. In addition, there is no guarantee as to which gas supply projects will eventually be built. If we allow the second project to catch up to the first, there is no assurance that either project will be built.
The second reason we are attracted to the Joint Proposal is that it addresses displacement capacity at the Otay Mesa receipt point. The sponsoring parties agree that up to 700 MMcfd of displacement capacity may be built, and that the funding parties will pay the incremental cost of the expansions. None of this displacement capacity will be rolled in. This provision of the Joint Proposal will permit gas supplies to enter through the Otay Mesa receipt point, and the costs of this displacement expansion will be borne by the funding parties.
There is one feature in the Joint Proposal that we do not care for. This provision allows the funding party to decide whether the additional capacity should be built as displacement capacity or expansion capacity. The Joint Proposal lets the funding party make this determination. SCE points out that expansion capacity should be preferred over displacement capacity because expansion capacity results in more gas supplies entering the marketplace. We agree with SCE that there may be situations where the utilities or the Commission should have input in deciding whether new or expanded capacity should be built on a displacement capacity or expansion capacity basis. Also, the FAR proposal and the unbundled FAR proposal have a workable solution in Step 3, as discussed later in this decision, for allowing market participants to bid on new capacity.
Due to the features of the Joint Proposal that we like and don't like, the Joint Proposal should not be adopted. We will, however, incorporate many of the aspects of the Joint Proposal into the FAR system, as described below. The features that we will incorporate into the FAR system are the following.
First, the procedure described in the first two sentences of the section titled "Determination of Facilities, Costs, and Character of New Takeaway Capacity" in Exhibit A of Exhibit 85 will be incorporated into the FAR system. As for the third sentence that provides for "access to all cost and engineering information," we agree with SDG&E and SoCalGas that this information may contain sensitive customer-specific information, as well as pipeline information that may pose security concerns. Accordingly, access to this kind of information is to take place at the offices of the utility, unless otherwise agreed to. In addition, any runs of a computer model shall be done in accordance with Rule 10.4 of our Rules of Practice and Procedure. In the event the parties requesting this kind of information believe that the utility is not providing this information in good faith, the requesting party may request the Commission's Energy Division to assist in determining whether certain information should be made available to the requesting party.
Second, all three of the funding options described in Exhibit A of Exhibit 85 shall be adopted and reflected in the Special Conditions of the proposed Schedule G-RPA that is contained in Exhibit 15. Regarding the first funding option, if a funding party decides to construct the needed facilities by itself, the planning and construction of the facilities will need to be coordinated with the utility and meet all utility-required safety requirements. As for the 20-year contract term referenced in the funding options, that term may be for a shorter period of time so long as all the construction costs are fully amortized over the shorter term.40 The determination as to whether the additional capacity should be built on an expansion capacity or displacement capacity basis is described later in this decision.
Third, the logic and theory behind the "Scheduling Rights for Expansion Capacity," the "Scheduling Rights for Displacement Capacity," and the "Scheduling Right Associated with Receipt Point Capacity Additions in the Southern Zone" that appear in Exhibit A of Exhibit 85 shall be incorporated into the open season process of the FAR system in the following manner.41
If a funding party builds new capacity or expands existing capacity on a displacement capacity basis at Otay Mesa, up to 700 MMcfd, and the funding party pays for it on an incremental cost basis, the funding party shall be eligible to receive a Step 1 set-aside for firm rights in the Southern Zone at Otay Mesa in the open season for the amount of capacity that the funding party paid for.42
If a funding party builds new capacity or expands existing capacity on an expansion capacity basis, and the funding party pays for it on an incremental cost basis, the funding party shall receive a Step 1 set-aside for the capacity that the funding party paid for.43
If a funding party builds new capacity or expands existing capacity on a displacement capacity basis, and the funding party pays for it on an incremental cost basis, the funding party shall be eligible to receive a Step 1 set-aside in the appropriate zone for the amount of capacity that the funding party paid for, but that set-aside shall be subject to nominations at other receipt points in the same transmission zone.44
If the costs of those facilities required to add new or expanded receipt point capacity receive rolled-in rate treatment by the Commission, all ratepayers shall have access to that capacity through Steps 1, 2 and 3 of the open season process.45
And fourth, to the extent the "Definitions" in Exhibit A of Exhibit 85 are needed to explain or clarify those provisions of the Joint Proposal which we incorporate into the FAR system, those definitions shall be incorporated into the FAR system.
SDG&E and SoCalGas shall be directed to incorporate the features of the Joint Proposal that we have adopted, as discussed above, into the FAR system that we discuss in more detail below.
The adoption of these key features from the Joint Proposal, and their incorporation into the FAR system will provide certainty to potential gas suppliers that their gas supplies will be able to access the southern California gas market. At the same time, the adopted features provide a set-aside capacity incentive for those parties who are willing to fund the cost of new or expanded capacity on an incremental cost basis, and assurance to ratepayers that the cost of this capacity will not be recovered in their rates.
d) FAR Proposal and Unbundled FAR Proposal
(1) Introduction
In this section, we compare and choose between the FAR proposal of SDG&E and SoCalGas, and the unbundled FAR proposal sponsored by Watson/IP/CCC/CMTA. The two key differences between the two proposals are putting SDG&E and SoCalGas at-risk for the recovery of their noncore backbone transmission costs, and the unbundling of the backbone transmission costs.
Several parties oppose both proposals and contend that a system of FAR is not needed in southern California. These parties contend that the two FAR proposals will result in less flexibility, increase complexity, increase costs, favor an affiliate of the utilities, and that the reservation charges and the credit-back mechanism are illegal. Many of the parties also propose a series of modifications to the two proposals should the Commission decide to adopt a system of FAR.
In the discussion which follows, we first make some general observations about the two proposals. We then address the opposition of the parties to both proposals, the key differences between the two FAR proposals, our selection of the FAR proposal, the unbundling of the five cents FAR reservation charge, and the parties' proposed modifications to the FAR proposal.
(2) Relationship to the CSA
The scoping memo for this proceeding raised the issue of whether the CSA adopted in D.01-12-018, and implemented and stayed in D.04-04-015, is still relevant in light of the history of this proceeding and the changes that have taken place since the CSA was adopted. 46 The CSA and the other settlements considered in D.01-12-018 were designed, in part, to create a system of allocation of capacity for southern California. This proceeding was initiated to consider proposals to allocate capacity. In response, the parties proposed five options on how to allocate gas transmission capacity in southern California. The five options are: the current system of capacity allocation, the FAR proposal, the unbundled FAR proposal, the Joint Proposal, and DRA's allocation method.
The FAR proposal and the unbundled FAR proposal are patterned after the CSA, but as noted in the descriptions of both proposals, vary from the CSA. Since the capacity allocation proposals before us today are different from what was adopted in the CSA, the CSA merely serves as a reference for deciding which of the capacity allocation methods we should adopt based on the options and evidence before us. Thus, the decisions regarding the adoption of the CSA (D.01-12-018) and the implementation of the CSA (D.04-04-015) are now moot as a result of today's decision and the adoption of a new gas market structure and capacity allocation method for SDG&E and SoCalGas.
(3) The FAR System In General
In contrast to the current system, the FAR proposal and the unbundled FAR proposal allow the holder of the FAR to determine the choice of gas supply that will flow through the receipt point. In addition, the FAR proposal moves the control of the SoCalGas receipt points from the FERC-regulated interstate pipelines to the holders of FAR on the transmission system of SDG&E and SoCalGas. As described earlier, a system of FAR allocates the transmission capacity so that the uncertainty under the current system of whether one's gas will be able to enter the transmission system of SDG&E and SoCalGas is eliminated. Under the current system, during a period of receipt point constraints, a customer does not have any assurance that its gas will be able to enter the transmission system. A system of FAR remedies that problem.
(4) Flexibility
The parties opposed to a system of FAR contend that the current system provides more flexibility, and that the FAR proposal and the unbundled FAR proposal will reduce their ability to get the gas they need from the supply source they want it from. Under the current system, an end-user may choose to have its gas delivered through an alternate receipt point.
We are not persuaded by the arguments of the parties who contend that the two FAR proposals will result in less flexibility than the current system. The current system is only flexible when there are not constraints on the system. During times of high demand at alternative receipt points, that flexibility is not available.
The two FAR proposals will not reduce flexibility, as there will be many different options for market participants to choose from. The two FAR proposals allow the holder of the FAR to move its gas through the designated receipt point to the designated delivery point in southern California. The holder of the FAR will also have alternate rights. These alternate rights allow a holder of a FAR to bring in gas through receipt points within the same zone and through receipt points outside the FAR holder's zone. To the extent there is any unused capacity on the system, interruptible access will be available. Market participants can also turn to the secondary market to meet their needs. With all of these tools available to the market participants, the two FAR proposals will continue to provide market participants with flexible options.
Adopting a system of FAR will also result in the creation of a citygate market for southern California.47 End-users will then have the option of purchasing gas at the producing basin, at the border, or purchasing gas at the citygate. The option of purchasing gas at the citygate is currently not available to end-users in southern California, and may be attractive to customers who do not want to hold FAR. Having multiple points at which end-users can purchase their gas will no longer restrict an end-user having to buy border gas, which reflects the highest priced gas for the southern California market.
The adoption of a system of FAR will also provide certainty to FAR holders that their gas can be delivered from the receipt point to the citygate. (See 5 R.T. 749; 10 R.T. 1504.) This in turn will encourage parties to enter into long-term gas supply contracts because of this assurance. Under the current system, an end-user lacks the assurance that its gas will be delivered if constraints occur on SoCalGas' system.
(5) Alleged Complexities of the FAR System
Several of the parties opposed to the two FAR proposals contend that the FAR system and the open season process will be too complex. We disagree.
Those who currently use the transmission system, and those who are interested in holding FAR, are large sophisticated gas customers. The FAR system will allow these market participants to get what they need in order to move gas to the market. Those who are not interested in holding FAR have other options such as buying at the citygate.
As with all new systems and procedures, there will be a learning curve to understand how the FAR system and the open season process will work. We are not persuaded by the argument that the new system of FAR will be too complex or too difficult to understand. We estimate that the new FAR system will not be fully operational until the first quarter of 2008. Conforming tariffs, as discussed below, will have to be filed within 45 days of the effective date of today's decision. This implementation schedule provides plenty of time for parties to understand how the new FAR system will work, what market participants will have to do, and what type of gas procurement strategies they should pursue. In addition, a similar system has been in place on PG&E's system for over eight years, and similar processes have been used on the interstate pipelines.
(6) Increased Costs
Some of the parties contend that the two FAR proposals will result in additional costs to market participants in order to understand the FAR system and to participate in the FAR open season.
As we discussed in the section above, market participants are going to have to invest some time in order to understand the workings of the new FAR system. The costs of transitioning from the current system to the new FAR system should not be insurmountable for the market participants. Even if there are new transaction costs for market participants and those costs are passed on to end-users, the competition in the marketplace is likely to minimize the effect of any additional transaction costs.
(7) Affiliate Relationship
Several parties contend that the two FAR proposals provide the affiliate of SDG&E and SoCalGas with an advantage over other market participants.
We are concerned with Sempra LNG's relationship to SDG&E and SoCalGas, but do not believe that the FAR system that we adopt today provides Sempra LNG with an advantage over other market participants.48 The parties complain that the zone arrangements and receipt points benefit the affiliate. However, under the FAR proposal, all FAR holders will have the option to use alternate receipt point rights within the same transmission zone, as well as outside the zone. As a result, a FAR holder in a transmission zone with only one receipt point could use the alternate receipt point in another zone.
As for the argument that Sempra LNG's use of displacement capacity at Otay Mesa disadvantages those who have to fund construction on an expansion basis, SDG&E and SoCalGas agreed that all new suppliers will be able to obtain some level of displacement capacity.
(8) Legality of Reservation Charge and
Credit-Back
This section addresses the legal objections to the imposition of the reservation charge under the two FAR proposals, and the operation of the credit-back mechanism under the FAR proposal.49
Several parties contend that the reservation charge under both of the FAR proposals are illegal. They contend that the FERC decided in Union Pacific Fuels, Inc., et a.l vs. SoCalGas, 76 FERC Par. 61,300 (1996)50 that an access fee cannot be charged on interstate pipeline shippers for the right to nominate gas into the SoCalGas system.
The facts addressed in the Union Pacific Fuels decision are different and distinguishable from the reservation charge that would be assessed on FAR holders. In Union Pacific Fuels, the FERC found the access charge to be unlawful because it was "a charge to interstate shippers for the act of moving gas over the Kern/Mojave pipeline and delivering it to SoCal rather than a charge for any service performed by SoCal after its receipt of the gas." (Union Pacific Fuels, page 62,495.) The reservation charge under the two FAR proposals is assessed on those market participants who have a FAR at a receipt point on the SDG&E and SoCalGas transmission system. The holder of the FAR has the firm right to have its gas transported over the transmission system to the citygate. The reservation charge at issue is being assessed for the right to access the SDG&E and SoCalGas receipt point, and to have the gas transported over the transmission system of SDG&E and SoCalGas. We therefore conclude that the reservation charge is not unlawful under the holding of Union Pacific Fuels.
We turn now to the credit back mechanism in the FAR proposal. The credit back mechanism proposes to credit the end-users of SDG&E and SoCalGas with the five cents per Dth reservation charge that all FAR holders would be required to pay. Some of the parties question whether the credit back mechanism discriminates against those who pay the reservation charge but do not receive the credit because they are not end-users.
The purpose of the credit-back mechanism is to credit end-users on the system with the five cents per Dth reservation charge that all FAR holders pay. The reservation charge provides the FAR holder with access to the transmission system. The transmission system has been paid for in rates by the end-users of SDG&E and SoCalGas. The shippers and marketers, who do not receive a credit-back, but who use the transmission system to deliver and sell their gas have not paid for the cost of the facilities that provide this service. It is entirely appropriate that these shippers and marketers pay for a share of the transmission facilities through the reservation charge in order to access the transmission system.51 The credit-back mechanism appropriately credits the reservation charge back to those who have paid for the transmission facilities in their rates. If the shippers and marketers are allowed a credit-back for the payment of the FAR reservation charge, they would end up paying nothing for the right to access the transmission system of SDG&E and SoCalGas on a firm basis.
Furthermore, under the system integration decision (D.06-04-033), the transmission rates of SoCalGas' end-use customers increased slightly due to the integration of the two transmission systems. In this context, the credit-back of the reservation charge helps to reduce the transmission rates of the end-use customers of SoCalGas whose rates were increased due to the system integration. We conclude that the credit back mechanism is not discriminatory. Furthermore, the replacement of the credit-back mechanism with the unbundling of the FAR reservation charge from the end-user's transmission rate eliminates any alleged discriminatory effect.
(9) At-Risk Provision
The unbundled FAR proposal is different from the FAR proposal due to the unbundling of the noncore backbone transmission costs, and because it puts SDG&E and SoCalGas at-risk for the recovery of these noncore backbone transmission costs.
SDG&E and SoCalGas oppose adoption of the at-risk provision. Their primary argument is that the at-risk provision would create the incentive to maximize their throughput on the backbone transmission system in order to recover the costs associated with the unbundled backbone transmission. They contend that such an incentive is contrary to the Commission's energy efficiency and conservation goals and therefore the at-risk provision should not be adopted.
Their other argument is that by putting them at-risk, this will provide an incentive for SDG&E and SoCalGas to keep a lid on their costs by using existing facilities instead of adding additional facilities.
Watson/IP/CCC/CMTA contend that placing SDG&E and SoCalGas at-risk will provide the utilities with an incentive to expand their services to new markets and to keep their rates competitive with competing suppliers.
The at-risk provision operates in conjunction with the proposal of Watson/IP/CCC/CMTA to unbundle the backbone transmission costs. As discussed in the next section, the 15.75 cents reservation charge, which approximates the noncore's backbone transmission costs, is likely to act as a deterrent to those market participants who want FAR. A lower reservation charge is needed to stimulate participation for holding FAR. Also, the FAR system that we adopt today will take some time for the utilities and market participants to adjust to the new market structure. With a lower reservation charge and the absence of an at-risk provision, that will provide a baseline for determining whether future adjustments to the FAR system should be made.
In addition, putting SDG&E and SoCalGas at risk would act as an incentive for them to maximize throughput on their system, which encourages more consumption of natural gas, and is contrary to the Commission's energy efficiency and conservation goals. Such a result should not be encouraged.
We find that including an at-risk provision in the FAR system is not appropriate at this time.
(10) Unbundling Provision
The unbundled FAR proposal removes the noncore backbone transmission costs from the rate for transmission and distribution. The reservation charge of 15.75 cents per Dth, which approximates these unbundled noncore costs, would be charged to holders of the FAR. The charge, in conjunction with the at-risk provision, is designed to recover part of the unbundled transmission costs. In contrast, the FAR proposal does not separate the noncore backbone transmission costs from the overall rate for transmission and distribution. Instead, under the FAR proposal, the end-users continue to pay the full cost of transmission and distribution, and the holders of the FAR pay the five cents reservation charge, which is then credited back to system end-users. The credit-back reduces the end-users' transmission and distribution rate. There is no credit-back under the unbundled FAR proposal since the holders of the FAR pay for the costs of transmission over the backbone transmission system.
Several of the parties, who are likely to be holders of FAR, oppose the unbundling of the backbone transmission costs. They contend that the unbundling of these costs will lead to a cost shift because those who are holders of FAR will end up paying all of the backbone transmission costs, while those who purchase their gas at the citygate will not pay the backbone transmission costs. In addition, some of these parties oppose the 15.75 cents per Dth reservation charge as too high, and that it will discourage market participants from holding FAR.
We agree that the 15.75 cents per Dth reservation charge is likely to discourage many market participants from holding FAR because of the high reservation charge. In order to encourage participation in the holding of FAR, the reservation charge needs to be set at a lower level. With more holders of FAR, the FAR holders and end-use customers will have more flexible options on where the gas can be made available and from whom the gas can be purchased.
In addition, the 15.75 cents per Dth reservation charge is intended to unbundle the cost of the backbone transmission costs from the end-user's transmission rate. However, none of the parties specifically identified what transmission assets should be designated backbone transmission assets. Accordingly, we do not believe that full unbundling of the backbone transmission costs is justified with today's adoption of a FAR system.
Several parties recommend in their comments to the ALJ's proposed decision that if the Commission decides to adopt the five cents per Dth FAR reservation charge, instead of the 15.75 cents per Dth charge, that the unbundling of the reservation charge from the end-user's transmission rate should still occur. These parties contend that the unbundling, together with the elimination of the credit-back mechanism, will also eliminate the legal objections to the adoption of a FAR system.
Upon reflection, the unbundling concept will be adopted in conjunction with a FAR reservation charge of five cents per Dth. Since the FAR reservation charge provides access to the FAR holder so that its gas can gain access at the receipt point for delivery to the designated delivery point, that charge represents part of the cost of transmission. It is appropriate, therefore, that this reservation charge of five cents per Dth be unbundled from the end-user's bundled transmission rate, and that the credit-back mechanism not be adopted. Through the unbundling of the FAR reservation charge, the end-user's transmission rate will be reduced by five cents per Dth. This unbundling will more closely align the FAR system that we adopt today for SDG&E and SoCalGas, with the gas market structure that is in place for PG&E. As part of the adopted FAR system, SDG&E and SoCalGas shall unbundle the FAR reservation charge of five cents per Dth from the end-user's bundled transmission rate.
We also agree with some parties that a cost-based FAR reservation charge tied to the cost of the backbone transmission system is desirable. We are adopting a system of FAR because of the potential for backbone transmission constraints, so establishing a cost-of-service FAR charge based on backbone transmission costs will send the appropriate price signals to users of the system. However, in the absence of a cost study identifying backbone transmission-related costs, we cannot adopt a cost-based rate in this decision. The BCAP is the appropriate proceeding to fully assess the cost of the backbone transmission system.
Therefore, we direct SDG&E and SoCalGas to include a cost study of the backbone transmission system in their next BCAP. We intend to incorporate a cost-based FAR charge into the FAR system in time for the second three-year open season of FAR. In the interim, it is important to implement a system of FAR, and a five cent reservation charge is appropriate at this time. Moving forward with a system of FAR now will give SDG&E, SoCalGas, market participants, and the Commission valuable experience with a FAR market structure in southern California, and will give FAR holders an assurance that they can bring gas into southern California on a firm basis.
Since we do not adopt the at-risk provision in this decision, SDG&E and SoCalGas should be authorized to establish a balancing account so that they will not be at risk for under-recovery of the unbundled FAR reservation charge revenues, and any over-recovery is refunded to ratepayers.
(1) The FAR System Model
Based on all of the above discussion, the adoption of a system of FAR, together with the unbundled FAR reservation charge and selected elements of the Joint Proposal, for SDG&E and SoCalGas is in the interests of all market participants and consumers. The FAR system will result in a rational system of allocating transmission system capacity that will assure gas suppliers, gas marketers, and end-users that their gas will be able to access the receipt point on the SDG&E and SoCalGas transmission system for delivery to the designated receipt point.
The model for the FAR system that we adopt today shall be the FAR proposal of SDG&E and SoCalGas, with an unbundled FAR reservation charge of five cents per Dth. The FAR proposal, with the unbundled FAR reservation charge, is being selected over the unbundled FAR proposal with the 15.75 cents reservation charge because it provides a better starting point for introducing a system of FAR to southern California. While the unbundling and at-risk provisions are in use for PG&E, we do not believe that full unbundling of the backbone transmission costs and the at-risk provision are ripe for adoption for SDG&E and SoCalGas at this time. Specifically, the unbundled FAR proposal charge of 15.75 cents per Dth is too high. We believe that this higher reservation charge could discourage a number of market participants from holding FAR, which could impact the options in the marketplace.
The FAR proposal shall be integrated with the unbundling of the five cents per Dth FAR reservation charge, and with those elements of the Joint Proposal that we discussed above. In addition, the parties have proposed modifications to the FAR proposal, some of which we adopt as discussed below. The adopted modifications to the FAR proposal shall also be incorporated into the FAR system.
(2) Modifications to the FAR System
(a) Introduction
The parties have proposed a number of modifications to the FAR proposal. In addition, the comments to the ALJ's proposed decision suggested a number of modifications to the proposed decision. The modifications that we adopt, as discussed below, are to be incorporated into the FAR system.
(b) The FAR System Rates
Under the FAR proposal, anyone holding a FAR would pay the reservation charge of five cents per Dth per day on a monthly basis. The rate for interruptible access would be on a volumetric basis up to five cents per Dth.
Some parties contend that the five cents reservation charge is not cost based and therefore should be rejected. We are not persuaded by this argument. The evidence in this proceeding indicates that the five cents per Dth reservation charge is lower than the embedded cost of the backbone transmission, and that the total transmission costs are around 16 cents. There is also evidence that the credit-back of the reservation charge will reduce the transmission rate of end-use customers. The FAR reservation charge is related to the cost of transmission.
Some contend that the reservation charge for FAR and the rate for interruptible access should be set at zero. Such a suggestion means that market participants would not have to pay anything for access to the transmission system. That could result in all customers trying to obtain as much capacity as possible in all steps of the open season process, and then hoarding or reselling the access rights in the secondary market for whatever the market is willing to pay. Such an outcome would be undesirable.
The five cents per Dth per day reservation charge, and the interruptible rate are appropriate. The reservation charge acts as a deterrent to market participants hoarding receipt point capacity. The reservation charge is being assessed on those who use the transmission system to move gas from the receipt points to the citygate. It is appropriate that the market participants who access the receipt points to transport their gas over the transmission system pay for a part of the transmission costs. Setting the reservation charge at zero would encourage hoarding, and the FAR holder would not have to pay for any of the costs of the transmission system.
The interruptible service discourages the hoarding of capacity. If a holder of a FAR decides not to use their right to receipt point capacity, SDG&E and SoCalGas should be permitted to market that unused capacity for up to five cents per Dth.
The proposed decision recommended that the FAR system use the five cents FAR reservation charge and that the reservation charge be credited back to end-users, as proposed by SDG&E and SoCalGas. In the comments to the proposed decision, several parties recommended that the five cents FAR reservation charge be unbundled from the end-user's transmission rates, which will reduce the end-user's bundled transmission rate by five cents per Dth. By doing so, there is no need to adopt the credit-back mechanism. The correlation of the five cents per Dth FAR reservation charge with a reduction of five cents in the end-user's bundled transmission rate has appeal because the FAR reservation charge reflects part of the cost of transmission.
Some parties oppose the 90/10 sharing/incentive mechanism for interruptible transmission revenues. The availability of interruptible service provides a check on those FAR holders who seek to maximize their financial gain by withholding FAR capacity during a time of need for capacity. Under the proposed G-RPA tariff, SoCalGas is obligated to "make available all unutilized firm receipt point access capacity on an interruptible basis ... ." (Ex. 15, Schedule No. G-RPA, Special Condition 67.) There is no need to provide SoCalGas with an incentive to sell unused receipt point access capacity when it is required under the tariff to do so. The proposal of SDG&E and SoCalGas for a shareholder incentive sharing mechanism for the revenues associated with interruptible receipt point access capacity is not adopted.
SCGC and Watson/IP/CCC/CMTA propose that the FAR revenues be credited back on the basis of average year throughput (equal cents per therm) instead of on a cold year throughput basis. Watson/IP/CCC/CMTA contend that if the FAR revenues are credited back on the basis of cold year throughput, core customers will receive a larger FAR credit per Dth than noncore customers. The rate design witness for SDG&E and SoCalGas points out that the difference in allocating the revenue credit on an average year throughput basis as opposed to a cold year throughput basis, is quite small. We agree with SCGC's argument that the FAR revenues bear no relationship to cold year throughput. Despite the small monetary difference, we will require SDG&E and SoCalGas to use average year throughput, instead of cold year throughput, to allocate the FAR reservation charge credit.
(c) Fuel Charge
Several parties oppose the proposed in-kind fuel charge of 0.28%. Under the current method, fuel costs are recovered on a lagged basis using a balancing account. SDG&E and SoCalGas contend that the in-kind fuel charge will recover the cost of operating the compressors on a more timely basis and better aligns the cost recovery with the cost causation.
The disadvantage that we see with imposing the in-kind fuel charge is that the shippers will be responsible for paying this cost upfront with in-kind fuel. When that in-kind fuel charge is coupled with the FAR reservation charge, it is understandable why the shippers are opposed to the in-kind fuel charge proposal. Under the existing cost recovery, these costs are recovered through the rates of the core and noncore customers. We believe that in designing a fair and balanced system of FAR, that the fuel charges should continue to be recovered in the rates of end-use customers instead of being paid for by the shippers in the form of in-kind fuel.
(d) Step 1 Modifications
SDG&E and SoCalGas oppose the proposed 90 MMcfd set-aside for OEHI at the Gosford interconnection. SDG&E and SoCalGas do not believe the set-aside at the Gosford interconnection is appropriate because OEHI has other delivery options, and because OEHI is delivering into the heavily used Wheeler Ridge transmission zone. SDG&E and SoCalGas contend that providing OEHI with a set-aside would disadvantage the pipelines delivering into Wheeler Ridge and the potential customers who want to obtain FAR in this zone.
Based on the testimony of the OEHI witness, and the reasoning for the set-asides for the other California producers, it is appropriate to have a set-aside of 90 MMcfd for OEHI at the Gosford interconnection. The interconnection was built at SoCalGas' urging so that the production at OEHI could avoid having to use Line 85, which was not capable of handling the gas volumes from OEHI. The access agreement and the construction agreement between SoCalGas, PG&E and OEHI contemplated that the Gosford interconnection would serve the gas production from OEHI, and that OEHI was to pay for the cost of those facilities. Based on those documents, OEHI should receive the benefit of what it bargained for. Although OEHI has other outlets for its gas production, the evidence suggests that it cannot reliably depend on obtaining access to the other outlets. OEHI shall be provided with a set-aside of 90 MMcfd in Step 1 at the Gosford interconnection.
PG&E requests a set-aside in Step 1 for five of the six G-XF long-term contracts that deliver into Kern River Station. SDG&E and SoCalGas point out that the holders of these G-XF contracts signed contracts for PG&E capacity without any assurance of SoCalGas providing firm access to the SoCalGas system.
The five G-XF long-term contracts, which specify Kern River Station as the delivery point, were approved by the Commission. In that respect they are similar to the set-asides for the four Commission approved long-term contracts that SDG&E and SoCalGas propose in Step 1. Accordingly, SDG&E and SoCalGas shall provide a set-aside for the five G-XF long-term contracts with PG&E at the Kern River Station receipt point.52
Exxon Mobil contends that it should receive a set-aside for its gas production from its Santa Ynez unit, which is located in federal waters offshore of California, and which delivers into the Coastal transmission zone. SDG&E and SoCalGas contend that because the production is located in federal waters, it does not qualify as a California producer, but the utilities are willing to provide Exxon Mobil with a set-aside if it signs a standard producer access agreement.
We do not agree that Exxon Mobil should be required to sign a standard producer access agreement in order to receive the set-aside.53 Although Exxon Mobil is located in federal waters offshore of California, SoCalGas included Exxon Mobil's gas production when it determined the amount of set-aside capacity for California producers. In addition, the gas produced by Exxon Mobil flows into the Coastal transmission zone. If other California gas producers who deliver their production into SoCalGas' transmission system receive a set-aside, Exxon Mobil should receive a similar set-aside without having to execute a new access agreement. SDG&E and SoCalGas shall include a set-aside for Exxon Mobil's production from its Santa Ynez unit in Step 1.
SCGC requests that set-asides be provided for noncore customers with long-term commitments on the upstream pipelines. SCGC notes that electric generation customers have long-term upstream contracts, but most noncore customers do not. Watson/IP/CCC/CMTA argue that the noncore upstream contracts never contemplated firm service onto the SoCalGas system. SCGC's request that a set-aside for noncore customers who have long-term contract commitments on the upstream pipelines is not adopted. Such a set-aside is likely to reduce the amount of capacity available to end-users at the most popular receipt points, and little, if any, capacity would be available to end-users and other market participants in Steps 2 and 3.
SDG&E and SoCalGas have proposed that each of the Oxnard 3 customers be provided with a set-aside up to their respective Tier I contract quantities, and that they receive a credit-back to maintain the benefit of the bargain that was agreed to originally in their Commission-approved long-term contracts.
SDG&E and SoCalGas are agreeable to basing the set-aside for the Oxnard 3 contracts "on the higher of Tier I volumes or the most recent annual average usage." (SDG&E and SoCalGas Reply Brief, page 36.) SDG&E and SoCalGas would allow the Oxnard 3, just as all noncore customers would be allowed to do in Step 2, to adjust their set-aside volume if they can demonstrate that their annual average usage will increase.
The utilities' proposal is substantially similar to the CCC's proposal that the set-aside be "based upon recent historical demand with adjustments to account for expected load growth as reasonably demonstrated by the customers." (CCC Opening Brief, page 7.) The CCC, however, ties its proposal to testimony in A.03-06-040, in which the CSA and the other settlements were considered. The CCC attached that testimony to Exhibit 43, and recommended that the CSA set- aside for the Oxnard 3 be "in an amount equal to their projected maximum daily demand for the initial term of the CSA." (Exhibit 43, Att. RTB-3, page 2; CCC Opening Brief, page 7.) We agree with the argument of SDG&E and SoCalGas that if the set-aside is based on "projected maximum daily demand," that this could lead to disputes. Since the Oxnard 3 would be permitted to adjust their set-aside under the utilities' proposal if they can demonstrate that their annual average usage will increase, we will adopt the wording used by SDG&E and SoCalGas. Accordingly, SDG&E and SoCalGas shall provide a set-aside to the Oxnard 3 based on the higher of their Tier I volumes or the most recent annual average usage. The Oxnard 3 shall be permitted to increase their set-aside if they can demonstrate that their annual average usage will increase.
The Oxnard 3 also contend they should only be required to pay for the access that they use, and that the charge should be on a volumetric basis.54 They contend that the credit-back proposal of SDG&E and SoCalGas will result in the Oxnard 3 paying more for capacity than they use, which conflicts with the long-term contracts. Since the credit-back mechanism is not being adopted, this issue is now moot.
In our earlier discussion regarding the Joint Proposal, we adopted elements of the Joint Proposal, including how the scheduling rights are to be incorporated into the FAR open season process. Four scenarios for how the scheduling rights will be converted into a FAR were listed.55 SDG&E and SoCalGas shall incorporate those four scenarios into the appropriate steps of the FAR system. Any FAR awarded under these four scenarios will be required to pay the five cents per Dth reservation charge.
SCE contends that the core should not be awarded set-aside rights for upstream contracts that expire during the three-year cycle. SDG&E and SoCalGas assert there is no reason to limit the rights of the core customers because under the FAR proposal, a set-aside for the core will only be permitted if the upstream contracts last for at least 18 of the 36 months of the three-year cycle.56 We agree with SDG&E and SoCalGas that the core set-aside language should govern which upstream core contracts are eligible for the core set-aside. If a qualifying core contract expires before the three-year term has expired, the utility has the flexibility with the set-aside to secure additional supplies to meet the core needs for the remaining time. Accordingly, SCE's suggestion is not adopted.
Under the FAR proposal, all FAR holders, including those who receive a set-aside in Step 1, would be allowed to re-contract. SDG&E and SoCalGas contend that the ability to re-contract allows all customers to match the FAR with upstream supply choices. SCE proposes to prohibit any re-contracting of capacity that was acquired as a set-aside in Step 1.
SCE contends that those who receive a set-aside in Step 1 should use it for its intended purpose, that of reliability.57 SCE's proposed prohibition would restrict how the holders of the set-asides could use them. Instead of being able to trade or sell the FAR that they receive in the set-aside, SCE's proposal would limit all holders of set-asides to ensure that the set-asides are serving the purpose for which they were created. SDG&E and SoCalGas believe that this is an intra-shipper issue, but point out that SCE's proposal would end up restricting a set-aside customer's ability to optimize their FAR.
SCE's point is well-taken. If someone receives a set-aside, that presumes there must be a good reason for doing so, and in theory the holder of the set-aside FAR should not be allowed to defeat the purpose of the set-aside. However, as SDG&E and SoCalGas point out, there may be situations where those with a set-aside, especially those that serve core loads, may be able to take advantage of cheaper priced gas from another receipt point. Restricting one's ability to trade or sell the FAR set-aside could disadvantage the core in that situation. In order to allow the holder of a FAR set-aside to have as much trading flexibility as possible, we decline to adopt SCE's proposed prohibition. As we discuss later, since we are adopting the suggestion to impose a price cap on the FAR in the secondary market, the price cap will limit the financial reward that a FAR set-aside holder may receive if it decides to trade or sell the FAR in the secondary market.58
Watson/IP/CCC/CMTA propose that the set-aside process for California producers should be based on a three-year historical average instead of historical peak average monthly production over the prior 12 months. They also propose that the California producers should have the ability to justify a set-aside greater than indicated by the historical data if the producer had historical peak month production that was shut in or restricted due to operating constraints, or if the producer can show the utility it has obtained permits and ordered equipment that will increase production above historical levels. SDG&E and SoCalGas point out that basing the California producer set-asides on peak deliveries in the last three years could affect the FAR available in the Wheeler Ridge zone since any capacity not taken on Line 85 could be used to increase the FAR at Wheeler Ridge.
The proposal of Watson/IP/CCC/CMTA to base the set-aside for California producers in Step 1 on an individual producer's peak month production delivered into the SoCalGas system over the most recent three-year period, instead of the proposed historical peak average monthly production over the prior 12 months, shall be adopted. We believe that the three-year historical average provides a better indicator of production for the California producers. Since we are adopting a three-year historical average for the California producers, there is no need to adopt their other proposal. If production is likely to increase, and the producer can justify the increase in production, the proposed tariff permits such a showing.
(e) Step 2 Modifications
SCE raised the issue about tolling agreements, and how Step 2 of the FAR proposal should account for these agreements. SDG&E and SoCalGas have no objection to SCE's approach as long as there is sufficient evidence that the plant owner is willing to forego its FAR in favor of the party providing the tolling service.
We agree with SCE that Step 2 of the open season process must account for the tolling agreements. Due to the way in which the FAR proposal and the tolling agreements were developed, Step 2 of the open season process needs to be clarified. Thus, we will require that when an end-use customer (i.e., the plant owner of an electric generation facility) of SDG&E or SoCalGas has contracted with a third party (i.e., with DWR or one of the California electric utilities) to supply natural gas for electric generation under the terms of a tolling agreement, that the Step 2 bidding rights is to be provided to the third party that supplies the natural gas for the electric generation. Furthermore, we direct SDG&E and SoCalGas to include the usage under the tolling agreements as part of the historical usage for the purpose of calculating the bidding rights of the third party responsible for obtaining the gas under the tolling arrangements. SDG&E and SoCalGas shall also meet with the parties providing the tolling service and with the electric generation plant owners, to develop a satisfactory release form agreeable to all affected parties.
Next, we address how the long-term EOR contracts of Aera and MSCC should be treated under the FAR proposal. Aera and MSCC expressed concern that it was not clear if they would be permitted to bid in Step 2 for FAR capacity. Exhibit 16 made it clear that Aera and MSCC would be treated like other noncore customers and would be permitted to bid for FAR capacity in Step 2.
Aera and MSCC assert that if they are able to obtain FAR or interruptible receipt point access service, that they should receive a dollar-for-dollar credit-back of the charge for the FAR or the charge for the interruptible service.59
In the event Aera and MSCC obtain and pay for the FAR reservation charge, SDG&E and SoCalGas propose that Aera and MSCC not receive a credit-back. SDG&E and SoCalGas consider these contracts to be interruptible contracts, and therefore no credit-back of the FAR reservation charge is warranted because of the interruptible nature of the contract. Aera and MSCC contend that the interruptible nature of their contracts was for curtailment purposes only.
We agree with the argument of Aera and MSCC that one's curtailment priority has no relationship to a customer's gas nominations. SoCalGas should unbundle the five cents reservation charge from the Aera and MSCC contract rates in the same manner as these charges are unbundled from the rates of other customers. This will place Aera and MSCC in the same position as other customers, permitting them to elect firm access rights in the amount and at the locations of their choosing without the risk of duplicative charges.
SWG recommends that in Step 2, local distribution companies be allocated the bidding rights it needs to serve their core extreme weather demands. SDG&E and SoCalGas point out that SWG would receive the same type of set-aside and maximum bidding rights that SDG&E and SoCalGas core customers will receive. They point out that SWG has options available to it such as the purchase of storage, or it can purchase additional capacity in Steps 2 or 3, or use interruptible transmission. These are the same options that the utilities and wholesale customers will have for their core customers.
We do not adopt SWG's recommendation. As SDG&E and SoCalGas point out, there are other options under the FAR system that SWG can use in order to ensure they have sufficient gas supplies to meet any extreme weather demand.
Some of the parties propose to eliminate the 75% receipt point capacity limit in Step 2, while others believe the limitation should be upheld. This limit operates to limit the bidding for capacity in Step 2 to 75% of the receipt point capacity less any amount that was set-aside in Step 1. Some of the parties concerned with the 75% limit believe that in certain situations it may limit the total amount of capacity available in a transmission zone to end-users in Step 2 and to all market participants in Step 3. They also contend that end-users may be forced to compete with marketers and shippers for capacity in Step 3 in order to satisfy their gas needs, even though end-users have paid for the cost of these facilities in rates. Sempra LNG proposes that the capacity limitation be based upon historical utilization by month at each individual receipt point using the five year average from 2001 through 2005. SDG&E and SoCalGas believe that the 75% limit on each receipt point's capacity is a reasonable balance, and that increasing or decreasing the total amount of capacity in Step 2 will have an effect on other market participants.
We have considered the various arguments about the 75% capacity limit. On the one hand, we are concerned that the end-use customers who pay for the transmission costs in their rates should get what they pay for. On the other hand, we recognize that the FAR system should provide all market participants with the opportunity to obtain FAR. In achieving a balance between the competing interests, we will adopt a slight variation on Sempra LNG's proposal. The limit on how much end-users can bid at any individual receipt point in Step 2 shall be limited to the historical utilization by month at each individual receipt point using the five year average from January 1, 2001 through December 31, 2005, less any Step 1 set-aside capacity.60
SCGC proposes that the base period for determining the customers' maximum Step 2 bidding rights should be based on the previous three years' experience rather than just one year. SCGC contends that for many customers, especially electric generators, usage can vary significantly from year to year due to weather and other factors. The FAR proposal calls for the maximum bidding in Step 2 to be based on "the twelve consecutive months of consumption ending four months prior to the start of the process to assign/award receipt point rights." (Exhibit 15, Schedule G-RPA, Sheet 9.)
In the Step 1 modification, we adopted a similar modification for the calculation of the California producers' set-aside. SCGC's proposal raises the same concern that usage can vary over a one-year period. Accordingly, SCGC's proposal that an end-user's base period for determining the customers' maximum Step 2 bidding rights shall be based on the 36 consecutive months of consumption ending four months prior to the start of the open season process.
SCGC is concerned about the FAR proposal's preference for annual bids over seasonal bids. Watson/IP/CCC/CMTA contend that such a preference is reasonable because annual bids provide greater economic value to the utilities and maximize the use of system capacity. SDG&E and SoCalGas contend that its method is preferable because monthly bids can create gaps in the use of capacity. We are not persuaded by SCGC's argument that the preference for an annual bid over a monthly bid should be eliminated. Also, with the set-aside for the upstream contracts of electric generators, they should be able to obtain most, if not all, of what they need.
SCGC proposes that the contract terms for Steps 1 and 2 should be for a two-year term instead of three years. SDG&E and SoCalGas contend that the three-year term provides for greater stability with respect to access rights, as well as the supply choices of end-use customers. We will leave the length of the contract terms in Step 1 and Step 2 at three years. The three-year term is an appropriate balance between having supply certainty and a preference for shorter term contracts.
(f) Step 3 Modifications
Several parties suggest that the 15-year contract term in Step 3 be reduced. The contract terms that parties recommend range from two years to 20 years. SDG&E and SoCalGas agreed during the hearing that the contract term in Step 3 should be reduced. The utilities, however, point out that the costs of any new or expanded capacity needs to be fully amortized over the shorter term. We shall permit the contract term in Step 3 to range from three years to 20 years. The minimum of a three-year contract term will make Step 3 consistent with the contract term in Step 1 and Step 2.
Some parties recommend that the Step 3 bids should be divided into two separate bids, one for existing capacity remaining after Step 2, and one for expansion and new capacity. They point out that this will avoid the problem in the SDG&E and SoCalGas proposal of having the cost of expansion and new capacity borne partially by those who want existing capacity only. We agree that Step 3 should take place in two bidding stages, one for existing capacity remaining after Step 2, and one for expansion and new capacity.
PG&E proposes that there be short-term FAR for any available capacity at Wheeler Ridge above 765 MMcfd, and that the short-term FAR be scheduled after the primary FAR. SDG&E and SoCalGas proposed in their rebuttal testimony to sell short-term FAR to take advantage of additional capacity that they reasonably expect to be available for shorter periods, but that the short-term FAR have the same priority as any other FAR. The proposal of the utilities will make more firm capacity available at Wheeler Ridge on a short-term basis. We agree with the approach of SDG&E and SoCalGas that short-term FAR service for Wheeler Ridge be made available to take advantage of any additional capacity that SDG&E and SoCalGas expect to be available for shorter periods.
The parties spent a lot of time in this proceeding litigating the issue of displacement capacity and expansion capacity. As discussed earlier, we have incorporated elements of the Joint Proposal into the FAR system which address displacement and expansion capacity. Instead of adopting the element in the Joint Proposal that a requesting party can choose whether to build on an expansion capacity or displacement capacity basis, we have decided, as clarified above,61 to use the FAR proposal's approach that the parties bid in Step 3 for new receipt point capacity or for expanding existing capacity. That leaves the door open for the Commission to decide whether facilities should be constructed on a displacement or expansion capacity basis.
As SCE points out, there may be situations where expansion capacity should be preferred over displacement capacity because an expansion capacity will result in an overall increase in pipeline capacity. Accordingly, SDG&E and SoCalGas shall contact the Energy Division regarding preliminary discussions with any third party to construct new capacity or to expand existing capacity on the utilities' transmission system. If the Energy Division believes the Commission should become involved in such a decision, we may require that an application be filed before allowing such a project to proceed. Such a process is consistent with our recent decision in D.06-09-039 where we required SoCalGas to monitor the receipt points and to provide us with semi-annual reports on such issues as the "rationale for expanding or not expanding the capability of a particular receipt point," and "why the company should or should not pursue receipt point expansion in response to existing or forecast constraints." (D.06-09-039, page 32.)
(g) Secondary Market
Kern River and SCE have proposed to put price caps on the secondary market transactions. SDG&E and SoCalGas contend that price caps are not needed, and that the holder of the FAR should receive the market value of the FAR. We view the price cap as a preventative measure to prevent a possible reoccurrence of some of the gaming that occurred during the energy crisis. Since today's decision adopts a system of FAR for SDG&E and SoCalGas, we believe that price caps on the price of the FAR in the secondary market will reduce the potential for future problems as we gain experience with the FAR system in southern California. In addition, we noted earlier that the set-asides in Step 1 should be used for their intended purposes. Establishing a price cap will help ensure that a holder of a FAR set-aside does not unduly profit from their set-aside. Accordingly, a price cap of 125% of the FAR reservation charge shall apply to all secondary market transactions.
As part of their FAR proposal, SDG&E and SoCalGas agree to provide quarterly reports and to post secondary market information on the EBB. SCE suggested that the name of the acquiring shipper be provided as part of the secondary market information that SDG&E and SoCalGas intend to provide. SCE's suggestion shall be incorporated into the market monitoring information that SDG&E and SoCalGas have agreed to provide in quarterly reports and the EBB.
SCE also proposes that any party that has more than 30% of the capacity at any receipt point be required to provide the Commission with the economic justification for that capacity. The amount of capacity that a party has will be reported in the quarterly reports that SDG&E and SoCalGas will be required to provide to us. We do not see the necessity at this time to require a FAR holder to justify its FAR holdings. The quarterly reports, and the daily operation of the FAR system, should reveal any potential market power issues.
(h) Continental Forge and SCE Settlement
Some of the parties contend that portions of the FAR proposal are inconsistent with the terms of the Continental Forge settlement or with the SCE settlement. We have reviewed the parties' arguments, as well as the exhibits in this proceeding, and do not believe that there are any provisions in either settlement that should prevent us from adopting the FAR proposal in this decision as the model for the FAR system. We also note that the Commission is reviewing the terms of the Continental Forge settlement and the SCE settlement in A.06-08-026, and will issue its decision on those settlements in that application.
The cost to implement the FAR system and the other services described in this decision are estimated to cost $3.5 million. SDG&E and SoCalGas propose that the FAR Memorandum Account be established to track the implementation costs. We approve the establishment of the FAR Memorandum Account to track and recover the costs of implementing the FAR system, and the other services, that we adopt in today's decision.
SDG&E and SoCalGas shall file an AL with the tariffs and services needed to implement this decision. The AL shall be filed within 45 days of the effective date of this decision. The tariffs and services shall be consistent with, and comply with the gas market structure that we adopt in today's decision. The ALs are subject to protest, and such protests shall be filed within 20 days after the AL has been filed. SDG&E and SoCalGas shall serve the respective ALs by e-mail on the service list to this proceeding, as well as on the interested parties who have requested notification of AL filings for SDG&E and SoCalGas.
In accordance with the implementation schedule proposed by SDG&E and SoCalGas, the FAR system approved in this decision shall be implemented and operational beginning no later than 365 days after a decision, resolution, or Energy Division has approved the implementing tariffs and related services.
Today's decision represents the start of a new gas market structure for southern California. In order to assess how this new system of FAR is working, and to determine if any adjustments or modifications need to be made, we should provide for a review process. This review process shall take place in an application filing by SDG&E and SoCalGas 18 months after the initial open season has concluded. In that proceeding, we intend to review how the system of FAR has operated, the impact on the gas market in southern California, the impact on end-use customers and market participants, and whether any changes or modifications to the FAR system are needed.62
13 The FAR proposal is described in the testimony of the SDG&E and SoCalGas witnesses, and in the proposed Schedule No. G-RPA attached to Exhibit 15.
14 The five transmission zones are the Southern transmission zone, the Northern transmission zone, the Wheeler transmission zone, the Line 85 transmission zone, and the Coastal transmission zone. (See Exhibit 15, Schedule No. G-RPA; Exhibit 30.)
15 This process is described in Special Condition 10 of the proposed G-RPA tariff in Exhibit 15.
16 As mentioned earlier, a wholesale customer may elect to have its noncore customers participate in Step 2.
17 The calculation for how the maximum bidding rights are determined is described in Exhibit 15 at pages 13 to 14, and in Special Condition 34 of the proposed Schedule No. G-RPA. Under the Step 2 process, an end-user would be allowed to justify a higher bidding right than the end-user's recent historical usage.
18 SDG&E and SoCalGas executed Collectible Systems Upgrade Agreements with Sempra LNG and Coral Energy to construct facilities that will allow 400 MMcfd of supplies to be received at Otay Mesa on a displacement basis.
19 The actual cost of the facility enhancement will be reflected in a revision to the G-RPA2 reservation charge. Once the construction of the facilities is completed and placed into service, an AL would be filed to update the costs and to establish the final reservation charge under the G-RPA2 rate schedule. After the AL is approved, the customers who executed the contract will be charged the approved reservation charge.
20 SCE agrees that its contract for capacity at Wheeler Ridge should be terminated. SCE notes that this contract is to expire in the fourth quarter of 2006, and that it provided notice of the termination of the contract to SoCalGas.
21 Special Condition 16 of the proposed Schedule No. G-RPA provides that a detailed summary of the completed secondary market transactions be posted on the EBB.
22 The proposed implementation schedule is set forth in Exhibit 15 at pages 32 and 33.
23 We do not separately list the arguments or the positions of each party in this decision. Instead, we have considered all the arguments of the parties and have selectively chosen representative samples from various parties' positions to provide the reader with an overview of the various arguments.
24 See D.94-01-048, pages 4-5; 76 FERC Par. 61,300 at page 62,495 (Sept. 19, 1996); 77 FERC Par. 61,283 (Dec. 19, 1996); 143 F.3d 610.
25 The Gosford interconnection is located east of Elk Hills and northwest of Wheeler Ridge. The interconnection is to a pipeline that is jointly owned by SoCalGas (Line 225) and PG&E (Line 7200) that runs from Kern River Station to Wheeler Ridge. The only gas that is capable of being delivered to the Gosford interconnection is the OEHI production.
26 The Oxnard 3 are three cogeneration customers who are members of the CCC. D.04-04-015 previously addressed the set-aside provision in the CSA as it relates to these three contracts. (See D.04-04-015, pages 27-29, 78, COL 33.)
27 The CCC filed a separate brief in support of the Oxnard 3 set-aside.
28 PG&E supports the proposal of other customers, in particular OEHI and SCGC, for set-asides. PG&E contends that as the market transitions to a new market structure, all customers with long-term contracts on upstream pipelines will face the same problems in acquiring FAR on the SoCalGas system to match their upstream holdings.
29 D.04-04-015 determined that SoCalGas' proposal to allow customers with interruptible long-term contracts to purchase interruptible backbone capacity to match their needs was reasonable and consistent with the CSA. Aera, MSCC, and Chevron USA Inc. filed an application for rehearing of D.04-04-015 but due to the pendency of this phase of the proceeding, the Commission has not acted on the rehearing application.
30 "Displacement" capacity refers to the construction of a receipt point that involves only the improvements necessary to allow the new supply to displace existing supplies so that the overall level of firm receipt point capacity remains unchanged. "Expansion" capacity refers to the construction of a receipt point that requires the improvements necessary to allow the new supply to increase the firm receipt point capacity of the entire system. (See Exhibit 40, page 7, fn. 6.)
31 SES notes that these concerns are reflected in the Joint Proposal, which SES is co-sponsoring. If the Joint Proposal is adopted by the Commission, the concerns of SES will be addressed. If the Joint Proposal is not adopted, SES believes its concerns should be reflected in the Commission's discussion about the construction of receipt point capacity.
32 The 6.25 cents is based on an assumed FAR reservation charge of five cents per Dthd.
33 Since the Southern transmission zone includes the Ehrenberg and Otay Mesa receipt points, alternate rights could be exercised by Sempra LNG within the zone without having to pay an additional fee.
34 The Continental Forge settlement and the SCE settlement are two separate settlements that SDG&E and SoCalGas have agreed to. SDG&E, SoCalGas, and SCE seek Commission approval of those two settlements in A.06-08-026. We will address those settlements in A.06-08-026 and do not do so here.
35 Several parties, including the CMTA and the IP, stated in their opening comments to the proposed decision, that if the five cents FAR reservation charge is adopted, the Commission should unbundle the charge from the end-user's transmission rate and the credit back mechanism be eliminated.
36 The sponsoring witnesses of the Joint Proposal clarified the first funding option in Volume 12 of the transcript at pages 1926-1927.
37 Coral Energy and Sempra LNG have each executed a CSUA with SDG&E and have advanced incremental costs totaling $10 million for displacement capacity of 400 MMcfd at Otay Mesa.
38 As mentioned earlier, the current procedures can result in a preference for certain gas supplies in the Northern transmission zone, or restricting the delivery of gas in the Wheeler Ridge transmission zone.
39 Clearwater proposes that the Joint Proposal be rejected, that a FAR system be adopted, and that bidding for new or expanded capacity take place in Step 3 of the open season process.
40 In the "Step 3 Modifications" discussion, we adopt a contract term of three to 20 years.
41 These three sections in Exhibit A of Exhibit 85 suggest that four types of scheduling right situations may be encountered that will require conversion from a scheduling right into a FAR set-aside, or other step in the adopted FAR system.
42 This is an appropriate set-aside because the funding parties agree that rolled-in capacity shall not apply to this Otay Mesa displacement capacity of up to 700 MMcfd. Such a result is also consistent with the general proposition that if a customer is required to pay for the construction of new facilities, that they should have a higher priority access to the use of those facilities (D.06-09-039, page 80), and with the incremental cost approach in D.04-09-022 at page 66.
43 This is consistent with D.06-09-039 at page 80 and D.04-09-022 at page 66.
44 This is consistent with D.06-09-039 at page 80 and D.04-09-022 at page 66.
45 Such a result is consistent with D.04-09-022 at page 66.
46 According to the terms of the CSA, the CSA terminated on August 31, 2006.
47 SCGC argues that its historical analysis of the citygate market for PG&E demonstrates that citygate prices have not benefited PG&E's customers. Watson/IP/CCC/CMTA contend that its analysis shows that PG&E's customers have benefited from the creation of a citygate market. Both analyses use different historical data and calculations to arrive at their conclusions. Having reviewed the evidence and the arguments critiquing each other's analyses, we find the analyis of Watson/IP/CCC/CMTA to be more persuasive.
48 If the parties detect that the operation of the FAR system is providing an unfair advantage to the affiliate in violation of the affiliate transaction rules, a complaint should be filed.
49 As discussed in the "Unbundling Provision" section, we do not adopt the credit-back mechanism. In response to comments on the ALJ's proposed decision, we have unbundled the FAR reservation charge of five cents per Dth from the end-user's transmission rate. We address the legal argument concerning the credit-back mechanism because a similar argument could be raised with respect to the unbundling of the five cents FAR reservation charge.
50 Referred to herein as Union Pacific Fuels. On rehearing before the FERC, the Union Pacific Fuels decision was affirmed on its merits in 77 FERC Par. 61,283. On the issue of ordering a refund, the FERC declined in 77 FERC Par. 61,283 to order a refund and held that the refund issue should be taken up with this Commission. The parties then petitioned the United States Court of Appeal for review. In 143 F.3d 610, that court held that the FERC acted reasonably when it concluded that the tariff at issue in Union Pacific Fuels was an access charge. The court further held that the FERC acted arbitrarily in refusing to act on the refund and remanded the refund issue to the FERC.
51 Similarly, the FAR reservation charge of five cents per Dth is appropriate because that charge pays for some of the costs associated with the utilities' transmission service. By unbundling the five cents reservation charge, that directly reduces the end-user's transmission rate by five cents.
52 The sixth G-XF long-term contract is already included in the Step 1 set-aside for SDG&E's core.
53 We extensively reviewed the access agreement that Exxon Mobil and its affiliate have with SoCalGas in D.06-06-065. We noted that SoCalGas has treated Exxon Mobil and its affiliate in a similar manner as other California gas producers. (D.06-06-065, page 42.)
54 The long-term contracts had an all volumetric rate structure.
55 Since we are not adopting the Joint Proposal, there is no need to discuss when a scheduling right will vest under the Joint Proposal.
56 See Special Conditions 19 and 20 of the proposed Schedule G-RPA in Exhibit 15.
57 It is arguable whether the set-asides for those other than the core in Step 1 are for reliability purposes.
58 We are concerned that if the holders of the FAR set-asides, other than to serve core load, consistently trade or sell their set-asides, that may mean the set-aside may not be appropriate or that it should be adjusted. SDG&E and SoCalGas should include their observations about the selling or trading of set-aside capacity when the FAR system comes up for review.
59 In their comments to the ALJ's proposed decision, Aera and MSCC propose that if the FAR reservation charge of five cents per Dth is unbundled, that the credit-back references should be eliminated and that they should be treated in the same manner as other customers.
60 When the subsequent open seasons are held, this five-year average should be advanced by two years to form a rolling five-year average. For example, the five-year average for the second open season should run from January 1, 2003 through December 31, 2007.
61 The clarification we refer to is dividing the Step 3 bid into two separate bids.
62 Further unbundling and the at-risk proposals are examples of changes or modifications that could be made.
