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Southern California Generation Coalition v. California Public Utilities Commission

California Court of Appeals, Second District, Third Division
May 19, 2008
No. B202987 (Cal. Ct. App. May. 19, 2008)

Opinion

NOT TO BE PUBLISHED

ORIGINAL PROCEEDINGS; petition for writ of review. Petition denied. Decisions affirmed. California Public Utilities Commission Proceeding No. A.04-12-004

Hanna & Morton, Norman A. Pedersen and T. Alana Steele for Petitioner.

Randolph L. Wu, Helen W. Yee and Pamela Nataloni for Respondent.

Steven C. Nelson for Real Party in Interest Sempra LNG.

Sutherland Asbill & Brennan and Rebecca Day for Real Party in Interest California Manufacturers & Technology Association.

W. Davis Smith, Lisa G. Urick, David J. Gilmore and Aimee M. Smith for Real Parties in Interest San Diego Gas & Electric Company and Southern California Gas Company.

Stephen E. Pickett, Douglas K. Porter and Gloria M. Ing for Real Party in Interest Southern California Edison Company.

Mark D. Patrizio and Keith T. Sampson for Real Party in Interest Pacific Gas and Electric Company.


KITCHING, J.

INTRODUCTION

On March 17, 2008, this court issued a Writ of Review to consider a Decision of respondent California Public Utilities Commission (CPUC) approving a proposal by real parties in interest Southern California Gas Company (SoCalGas) and San Diego Gas & Electric Company (SDG&E) to establish a system of firm access rights (FAR) to allocate transmission capacity of natural gas from upstream pipelines through receipts points into the SoCalGas and SDG&E integrated natural gas transmission system.

The CPUC approved the FAR system in Decision 06-12-031 (D.06-12-031) on December 14, 2006. Petitioner Southern California Generation Coalition (SCGC) filed an application for a rehearing, which the CPUC denied in Decision 07-09-046 (D.07-09-046). SCGC then filed in this court a verified petition for a writ of review.

In this writ proceeding, the CPUC Decisions under consideration include D.06-12-031 and D.07-09-046. SCGC asserts that in D.06-12-031, the CPUC did not make sufficient factual findings on material issues to justify the conclusion that the time was ripe for implementing the FAR system. SCGC also asserts that the actual factual findings made by the CPUC are not supported by substantial evidence. SCGC further asserts that D.06-12-031 is impermissibly discriminatory in the manner in which it allocates the FAR system access rights, called set-asides, to various users of natural gas.

SCGC seeks an order nullifying the foregoing CPUC Decisions. Alternatively, SCGC seeks an order remanding the matter to the CPUC to make additional material factual findings and to set forth sufficient evidence to justify the findings. SCGC also seeks a stay and injunctive relief to restrain the CPUC and the real parties in interest from implementing the new system of access rights and charges.

We affirm D.06-12-031 and D.07-09-046 and dismiss the writ petition. The CPUC supported the conclusion that the time was ripe for adoption of the FAR system in Southern California with separately stated findings of fact on a number of material issues, and those findings of fact were supported by substantial evidence. In addition, the “set-asides” granted to some, but not all, of the customers of SoCalGas and SDG&E were reasonable under the circumstances.

PROCEDURAL AND FACTUAL BACKGROUND

1. The Parties

Petitioner SCGC is an association of gas-fired electrical generators located throughout California. The purpose of the association is to promote the interests of the electrical generators before the CPUC and other governmental bodies and agencies.

Respondent CPUC is the administrative agency charged with regulating public utilities pursuant to Article XII of the California Constitution and the Public Utilities Act.

All statutory references are to the Public Utilities Code, unless stated otherwise.

Real Parties in Interest SoCalGas and SDG&E are public utilities within the meaning of section 216, electrical corporations within the meaning of section 218 and gas corporations within the meaning of section 222. SoCalGas and SDG&E were parties to the CPUC proceedings below.

Real party in interest Southern California Edison (SCE) is a public utility within the meaning of section 216 and an electrical corporation within the meaning of section 218. Petitioner SCGC failed to identify SCE as a real party in interest in the petition for writ review. SCE is a customer of SoCalGas and would be affected by the resolution of this matter. SCE was an active party to the CPUC proceedings below. SCE is therefore a real party in interest.

Real party in interest California Manufacturers & Technology Association (CMTA) is a trade association of manufacturing and technology companies, many of whom are customers of SoCalGas and SDG&E. CMTA was a party to the CPUC proceedings below.

Real party in interest Pacific Gas and Electric Company (PG&E) is public utility within the meaning of section 216, an electrical corporation within the meaning of section 218 and a gas corporation within the meaning of section 222. PG&E is the predominant gas and electric utility in northern and central California. PG&E was a party to the CPUC proceedings below.

Real party in interest Sempra LNG (SE LNG) is an affiliate of SoCalGas and SDG&E. SE LNG is constructing a facility in northern Mexico which is intended to deliver natural gas to California. SE LNG was a party to the CPUC proceedings below.

2. An Introduction to the Method for Delivering Natural Gas on the SoCalGas/SDG&E Transmission Pipeline System

The real parties in interest presented the following background information in their answer to the petition for writ of review. We set forth this apparently undisputed information in order to present a more thorough background of the natural gas industry in Southern California.

Natural gas is produced from wells that extract the gas from below ground surface. On one hand, some of the gas received by SoCalGas and SDG&E is delivered by gas producers located within SoCalGas’s service territory in California. On the other hand, some of the gas received by SoCalGas and SDG&E is delivered by pipeline companies whose pipelines are located “upstream” of the SoCalGas/SDG&E pipeline transmission system. The pipeline companies include interstate pipelines which are regulated by the Federal Energy Regulatory Commission (FERC). The interstate pipeline companies deliver gas across multiple state lines from producing wells located in Texas, Oklahoma, New Mexico and the Rocky Mountains. The record indicates that the pipeline companies do not necessarily produce the natural gas. In other words, there are also out-of-state and international (Canadian and Mexican) natural gas producers that ship their gas to Southern California by means of the pipelines operated by the interstate pipeline companies.

The Canadian gas is transported from Canada primarily through the pipeline system of PG&E before reaching the SoCalGas/SDG&E integrated transmission system. In addition, liquefied natural gas is also transported by ocean liner. Real party in interest SE LNG is constructing a facility in Baja California, Mexico to receive and “regasify” the liquefied natural gas.

SoCalGas and SDG&E physically receive the natural gas supplies from the upstream suppliers and from the California producers at “receipt points,” which are located within Southern California “zones.” The SoCalGas/SDG&E pipelines which receive natural gas are usually large-diameter, high-pressure pipelines called “transmission” lines. These high-pressure lines deliver natural gas to a few large-scale customers. Most of the natural gas is delivered to a storage field, such as an abandoned underground gas reservoir, or to the SoCalGas/SDG&E distribution system where the gas is then delivered to the majority of customers at lower pressures.

The capacity of the SoCalGas and SDG&E transmission lines to move gas away from the receipt points is called “takeaway” capacity. The point where the transmission lines connect with the smaller, lower-pressure distribution pipelines is called the “citygate.”

According to the CPUC in D.06-12-031, there are five transmission zones in the SoCalGas/SDG&E transmissions system. The zones are: (1) the Southern zone, (2) the Northern zone, (3) the Wheeler zone, (4) the Line 85 zone, and (5) the Coastal zone. (San Diego Gas & Elec. Co. (Cal.P.U.C., Dec. 14, 2006, Dec. No. 06-12-031) [2006 WL 3858043 at p. *5, fn. 14].) Each transmission zone has one or more receipt points.

As explained by the real parties in interest in their answer to the writ petition, and apparently undisputed by SCGC, the real parties have “noncore” and “core” customers. Specifically, “noncore customers” are larger customers that burn 20,800 therms of gas per month or more and generally include electric generating facilities, large manufacturing plants, and oil refineries. For noncore customers, SoCalGas and SDG&E provide only natural gas transportation service. The noncore customers purchase their own natural gas commodity and arrange for it to be delivered to the SoCalGas/SDG&E transmission system. The noncore customers frequently rely upon natural gas marketers to obtain their gas supplies.

“Core customers” burn less than 20,800 therms of gas per month and include residential and small commercial/industrial customers. For core customers, SoCalGas and SDG&E purchase the natural gas commodity from a gas producer or gas marketer, arrange for the gas to be delivered to the SoCalGas/SDG&E pipeline system, and transport the gas on the SoCalGas/SDG&E pipeline system to the customer’s premises.

3. The System of Capacity Allocation Prior to Adoption of the FAR System

In the CPUC Decision at issue in the writ proceeding, D.06-12-031, the CPUC explained the system of allocating the capacity on the SoCalGas transmission system to natural gas producers prior to the adoption of the FAR system. We quote this explanation in Appendix A, post, pages A-1 – A-2, to this opinion. Here, we summarize the CPUC’s description of this pre-FAR system.

The natural gas producers and pipeline companies have the ability to deliver substantially more natural gas to the SoCalGas/SDG&E integrated transmission than the utilities can receive and “redeliver” to their customers. In fact, the delivery capability is almost twice as large as the takeaway capacity. As new gas supply sources are created, the upstream delivery capability is expected to increase. Due to the difference between the delivery capability and the take-away capacity, problems in the delivery of natural gas can result in what the parties refer to as a “mismatch” or “bottleneck.” (San Diego Gas & Elec. Co. (Cal.P.U.C., Dec. 14, 2006, Dec. No. 06-12-031) [2006 WL 3858043 at p. *4].)

Under the system prior to FAR, SoCalGas allocates receipt point takeaway capacity to the upstream pipelines on a daily basis. The operators of the upstream pipelines then allocate the delivery capacity among its shippers using the capacity allocation rules of the upstream interstate pipelines, which have been approved by the FERC. When the shippers’ volumes on the pipelines 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. (San Diego Gas & Elec. Co., supra, [2006 WL 3858043 at p. *4].)

The parties do not define the nature of the upstream shippers’ contractual rights. The record suggests that these are contracts between the natural gas producers and the pipeline companies which deliver the natural gas to the SoCalGas/SDG&E transmission system.

The process of allocating the amounts of natural gas which can be delivered into the SoCalGas/SDG&E transmission system can result in a situation where access to the SDG&E/SoCalGas system is available only on an interruptible basis. In other words, the amount of natural gas that a particular shipper can deliver into the SoCalGas/SDG&E transmission system can fluctuate from day to day. (San Diego Gas & Elec. Co., supra, [2006 WL 3858043 at pp. *4-5].)

The utilities, SDG&E and SoCalGas, asserted before the CPUC that this allocation method frustrates both suppliers and end-users, creates confusion in the marketplace, and does not necessarily allow the lowest cost gas to reach the end-use markets. (San Diego Gas & Elec. Co., supra, [2006 WL 3858043 at p. *5].)

4. CPUC Considers Reforms to California Natural Gas Market Structure

In 1998, the CPUC considered and identified reforms to the natural gas market structure in California in order to foster market competition and benefit California natural gas consumers. (Regulatory Structure Governing California’s Natural Gas Industry (Cal.P.U.C., Jan. 21, 1998, 98-01-011) [1998 WL 209624].)

In Rulemaking Proceeding 98-01-011, the CPUC stated: “The goal of this rulemaking is to assess the current market and regulatory framework for California’s natural gas industry. We also plan to consider reforms to the current regulatory framework which emphasize market-oriented policies to benefit all California natural gas consumers. We are concerned that California consumers have not fully benefited from past natural gas reforms. The Commission, in its electric restructuring policies, has sought to bring small consumers the benefits of direct, unfiltered access to competitive services. We establish this rulemaking to ensure that all California consumers have a multitude of meaningful choices in energy services and that they have every opportunity to benefit from the greater efficiencies and service innovations we expect from competitive energy markets.” (Regulatory Structure Governing California’s Natural Gas Industry, supra, [1998 WL 209624 at p. *50].)

As a result of the foregoing rulemaking proceeding in 1999, the CPUC issued a decision identifying options for changes to the market structure of the natural gas industry in California. (Regulatory Structure Governing California’s Natural Gas Industry (Cal.P.U.C., July 8, 1999, 99-07-015) [1999 WL 699509].) There, the PUC explained: “In this rulemaking proceeding, we are assessing the current market and regulatory framework for California’s natural gas industry with the goal of identifying appropriate reforms and reporting our findings to the Legislature. . . . [¶] After review of the record established through the Market Conditions hearings, in the comments to the Market Conditions reports, in briefs and oral argument, and in comments on the report of the Division of Strategic Planning, we have identified the most promising options for further consideration. . . . [¶] The model we seek to explore further is one that preserves the utilities’ traditional role of providing fully-integrated default service to core customers, while clearing obstacles to the competitive offering of gas commodity, transmission, storage, balancing and other services for all customers in the service territories of regulated local distribution companies throughout the state. We find significant benefits for consumers in retaining this overall utility structure. At the same time, the changes we propose represent significant steps toward mitigating any potential anti-competitive behavior as a result of the utilities’ continuing ability to offer both traditional monopoly and competitive natural gas services.” (Id. at p. *6.)

In the July 8, 1999, Decision, the CPUC also explained: “We would extend certain improvements recently implemented in the [PG&E] service territory to ensure that they remain in effect beyond the limits of the Gas Accord and enact similar reforms in the [SoCalGas] service territory. These improvements include the creation of tradable access rights [i.e., FAR] to transmission and storage assets and the development of a secondary market for those rights. We would build upon the PG&E model by directing the utilities to create and maintain electronic bulletin boards that enable market participants to complete secondary transactions in a timely manner. In addition, we would enable customers to have more options in balancing services by directing the utilities to offer separate balancing rates and allowing customers to elect to pay for greater or lesser imbalance tolerances.” (Regulatory Structure Governing California’s Natural Gas Industry, supra, [1999 WL 699509 at p. *6].)

The CPUC invited all interested parties to submit detailed cost/benefit analyses of the various changes being proposed to the structuring of the natural gas market. The CPUC noted that a “stakeholder-generated solution” was preferred because “those who participate in the natural gas marketplace are in the best position to understand and accommodate underlying interests.” (Regulatory Structure Governing California’s Natural Gas Industry, supra, [1999 WL 699509 at p. *7].)

5. The CPUC Adopts Comprehensive Gas Settlement Agreement

On December 11, 2001, the CPUC issued Decision 01-12-018. There, the CPUC adopted the Comprehensive Gas Settlement Agreement (CSA). (Regulatory Structure Governing California’s Natural Gas Industry (Cal.P.U.C., Dec. 12, 2001, Dec. No. 01-12-018) [2001 WL 171241].) The CPUC intended the CSA to modify the regulatory and market structure for regulating the transportation and storage of natural gas on the SoCalGas and SDG&E transmissions systems. In the decision, the CPUC explained: “We believe that the [CSA] will provide significant benefits to all utility customers by allowing customers access to firm tradable transmission rights on SoCalGas’ system. The costs associated with intrastate backbone transmission will be unbundled for noncore customers. Noncore customers will be able to acquire intrastate backbone transmission capacity through an open season or purchase gas at the citygate. The utilities’ retail core procurement department will continue to reserve interstate capacity, intrastate backbone transmission, and storage to meet the requirements of retail core procurement customers. These changes will provide SoCalGas (and SDG&E) customers with numerous new service choices, and the opportunity to reduce costs by avoiding services that they do not need. The availability of firm, tradable transmission rights will allow customers to place an increased reliance on longer-term firm contracts. We anticipate that this increased reliance on longer-term contracts will bring with it badly needed price stability and rate certainty to all gas customers.” (Id. at p. *362.)

6. The CPUC Orders SoCalGas to File an Application to Implement the CSA, Decision 01-12-018

On June 30, 2003, SoCalGas filed Application 03-06-040 to implement the CSA. (Southern California Gas Company (Cal.P.U.C., Apr. 1, 2004, Dec. No. 04-04-015) [2004 WL 784888 at p. *1].) Following an evidentiary hearing, the CPUC issued a stay regarding implementation of the CSA. (Ibid.) The CPUC explained: “Although we are staying implementation of this decision, we fully support a market structure that includes firm tradable rights.” (Id. at p. *34.) Subsequently, the CPUC also ordered SoCalGas and SDG&E to file an application regarding their FAR proposals. (Order Instituting Rulemaking to Establish Policies and Rules to Ensure Reliable, Long-Term Supplies of Natural Gas to California (Cal.P.U.C., Sept. 2, 2004, Dec. No. 04-09-022) [2004 WL 2138338 at p. *48].)

7. SoCalGas and SDG&E File Application A.04-12-004 to Implement Their FAR Proposals

On December 2, 2004, SoCalGas and SDG&E filed Application No A.04-12-004. There, the utilities proposed a system for integration of the SoCalGas and SDG&E transmission systems. The utilities also proposed implementation of the FAR system. (San Diego Gas & Elec. Co., supra, [2006 WL 3858043 at p. *3].) The CPUC bifurcated the system integration proposal from the FAR proposal. The CPUC approved the proposal for system integration in a decision (D.06-04-033), which is not at issue in this writ proceeding. (Ibid.)

8. CPUC Issues Decision 06-12-031 Approving FAR System

With respect to the FAR system, the CPUC received over 100 exhibits and conducted 12 days of evidentiary hearings. (San Diego Gas & Elec. Co., supra, [2006 WL 3858043 at p. *3].)

On December 14, 2006, the CPUC issued D.06-12-031 in which the CPUC implemented the FAR proposal. (San Diego Gas & Elec. Co., supra, [2006 WL 3858043 at p. *1].) This is the decision at issue in this writ proceeding.

In D.06-12-031, the CPUC established the FAR system for southern California. The CPUC explained the FAR system generally: “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 [of FAR rights] 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. . . . 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.’ 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.” (San Diego Gas & Elec. Co., supra, [2006 WL 3858043 at p. *5, fn. omitted].)

“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. . . . ¶ 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. . . . [¶] 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. . . . 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.” (San Diego Gas & Elec. Co., supra, [2006 WL 3858043 at p. *6].)

“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. . . . 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.” (San Diego Gas & Elec. Co., supra, [2006 WL 3858043 at p. *7].)

“Step 2 provides for end-use customers 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. 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.” (San Diego Gas & Elec. Co., supra, [2006 WL 3858043 at p. *7, fns.omitted].)

“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. 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.” (San Diego Gas & Elec. Co., supra, [2006 WL 3858043 at p. *8, fn. omitted].)

“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 . . . .” (San Diego Gas & Elec. Co., supra, [2006 WL 3858043 at p. *8].)

“Under the FAR proposal, all unutilized firm receipt point access capacity will be made available on an interruptible basis . . ., 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.” (San Diego Gas & Elec. Co., supra, [2006 WL 3858043 at p. *9].)

9. The CPUC’s Factual and Legal Findings in Decision 06-12-031

In D.06-12-031, the CPUC made factual and legal findings. SCGC contends that certain factual findings are not supported by substantial evidence. To place the disputed factual findings in context, we quote many of the factual findings made by the CPUC, as well as those findings that SCGC challenges. SCGC asserts that factual findings 7, 9, 16, 18, 19, 20, 26, and 27 are not based upon substantial evidence, but constitute conjecture.

In Appendix B, post, pages B-1 - B-10, to this opinion, we set forth a complete list of the CPUC’s factual and legal findings, as well as its order implementing the FAR system.

“1. The origin of this proceeding can be traced back to R.98-01-011 wherein we considered and identified appropriate reforms to the natural gas market structure in California.

“2. D.99-07-015 acknowledged that PG&E’s Gas Accord market structure should be considered for SoCalGas.

“3. D.01-12-018 adopted the CSA, which called for a system of firm tradable transmission rights on SoCalGas’ backbone transmission system, the unbundling of the backbone costs from transportation rates, and an at-risk rate structure for the recovery of the backbone transmission costs. [¶] . . . [¶]

“7. 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 integrated transmission system, problems in the delivery of gas can result.

“8. Under the current system of allocating capacity on the SDG&E and SoCalGas transmission system: (1) end-use customers are the only ones who can transport gas; (2) SoCalGas allocates the available receipt point capacity to the upstream pipelines daily; and (3) the upstream interstate pipelines allocate the capacity among their shippers using their FERC-approved capacity allocation rules.

“9. The current system of capacity allocation can result in a situation where access to the system is available only on an interruptible basis, shippers’ gas supplies are pro-rated, and receipt points are constrained.

“10. SDG&E and SoCalGas’ FAR proposal would allocate access rights to the capacity at a particular receipt point on the integrated transmission system to various market participants using a three-step open season process. [¶] . . . [¶]

“15. The time is ripe to adopt a system of FAR for [S]outhern California.

“16. The basic underlying system of firm tradable transmission rights has worked and functioned well in [N]orthern California. [¶] . . . [¶]

“18. 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.

“19. With the possibility of [SE LNG] supplies flowing into [S]outhern California, and other changes in the gas market, receipt point constraints may occur again at other receipt points.

“20. Under the current system, end-users face uncertainty over whether their gas will flow through a constrained receipt point. [¶] . . . [¶]

“26. The FAR proposal will continue to provide market participants with flexible options and result in the creation of a citygate market for [S]outhern California.

“27. The adoption of the FAR proposal provides certainty to FAR holders that their gas can be delivered from the receipt point to the citygate, which in turn will encourage parties to enter into long-term gas supply contracts.

“28. The concerns regarding the FAR proposal’s complexity, increased costs, and affiliate preference are unwarranted.” (San Diego Gas & Elec. Co., supra, [2006 WL 3858043 at p. *67].)

In its “Conclusions of Law” and order implementing D.06-12-031, the CPUC adopted the FAR system for the integrated gas transmission system of SDG&E and SoCalGas based upon the likelihood that the constraint problems which have occurred in the past are likely to occur again, and based upon the conclusion that long-term contacts should be encouraged as a matter of public policy. (San Diego Gas & Elec. Co., supra, [2006 WL 3858043 at pp. *67-69].)

Notably, the CPUC also ordered that “[a] review process of the FAR system will be conducted to assess how the FAR system is working, and whether any changes or modifications to the FAR system are needed.” (San Diego Gas & Elec. Co., supra, [2006 WL 3858043 at p. *68].)

10. PUC Denies Application for Rehearing

On September 27, 2007, the PUC issued Decision 07-09-046, modifying Decision 06-12-031 and SCGC’s application for rehearing of Decision 06-12-031. SCGC then filed with this court a verified petition for writ of review.

CONTENTIONS

SCGC contends: (1) the CPUC did not make sufficient separate findings of fact resolving the material issues to support the ultimate finding that the FAR system was necessary and placed consumers in as good or better position than under the current system of capacity allocation; (2) the actual factual findings made by the CPUC are not supported by substantial evidence; and (3) the CPUC violated SCGC’s rights by allegedly granting individual capacity set-asides on an ad hoc basis, which was discriminatory. SCGC asserts that the CPUC failed to explain the bases for determining which customers should receive set-asides and the difference in the amount of the set-asides depending upon the type of customer.

STANDARD OF REVIEW

Pursuant to section 1756, subdivision (a), this court has jurisdiction to review CPUC decisions. (Southern Cal. Edison Co. v. Public Utilities Comm. (2005) 128 Cal.App.4th 1, 9.) Section 1705 provides that CPUC decisions “shall contain, separately stated, findings of fact and conclusions of law by the [CPUC] on all issues material to the order or decision.”

Section 1756, subdivision (a), provides in pertinent part: “Within 30 days after the commission issues its decision denying the application for a rehearing . . . any aggrieved party may petition for a writ of review in the court of appeal . . . for the purpose of having the lawfulness of the original order or decision or of the order or decision on rehearing inquired into and determined.”

Section 1757 governs judicial review of the [CPUC] decisions. Pursuant to section 1757, subdivision (a), review by this court “shall not extend further than to determine, on the basis of the entire record which shall be certified by the [CPUC], whether any of the following occurred: [¶] (1) The [CPUC] acted without, or in excess of, its powers or jurisdiction. [¶] (2) The [CPUC] has not proceeded in the manner required by law. [¶] (3) The decision of the [CPUC] is not supported by the findings. [¶] (4) The findings in the decision of the [CPUC] are not supported by substantial evidence in light of the whole record. [¶] (5) The order or decision of the [CPUC] was procured by fraud or was an abuse of discretion. [¶] (6) The order or decision of the [CPUC] violates any right of the petitioner under the Constitution of the United States or the California Constitution.”

Pursuant to section 1757, subdivision (b), this court is prohibited from holding a trial de novo, taking evidence (other than as specified by the California Rules of Court), or exercising its independent judgment on the evidence. Moreover, CPUC factual findings are not open to attack for insufficiency of the evidence if they are supported by any reasonable construction of the evidence. (Toward Utility Rate Normalization v. Public Utilities Com. (1978) 22 Cal.3d 529, 537-538.)

In addition, the CPUC is not an ordinary administrative body, but a constitutional body with broad legislative and judicial powers. (Wise v. Pacific Gas & Electric Co. (1999) 77 Cal.App.4th 287, 300.) CPUC decisions are presumed valid. (Greyhound Lines, Inc v. Public Utilities Com. (1968) 68 Cal.2d 406, 410-411.) The CPUC’s interpretation of the Public Utilities Code is not to be disturbed unless the interpretation fails to bear a reasonable relation to statutory purposes and language. (Ibid.)

DISCUSSION

1. The CPUC Complied With Section 1705

Section 1705 requires that CPUC decisions “shall contain, separately stated, findings of fact and conclusions of law by the [CPUC] on all issues material to the order or decision.” Although the CPUC has discretion to determine which factors are relevant to a particular decision, the CPUC must state those factors and make findings on the material issues that ensue from those factors. (California Motor Transport Co. v. Public Utilities Com. (1963) 59 Cal.2d 270, 275.) The separately stated findings of fact and conclusions of law “afford a rational basis for judicial review and assist the reviewing court to ascertain the principles relied upon by the commission and to determine whether it acted arbitrarily, as well as assist parties to know why the case was lost and to prepare for rehearing or review, assist others planning activities involving similar questions, and serve to help the [CPUC] avoid careless or arbitrary action.” (Greyhound Lines, Inc. v. Public Utilities Com. (1967) 65 Cal.2d 811, 813.) Notably, “[e]very issue that must be resolved to reach that ultimate finding is ‘material to the order or decision.’ Statutes like section 1705 have been held to require findings of the basic facts upon which the ultimate finding is based.” (California Motor Transport Co. v. Public Utilities Com., supra, at p. 273.)

Finding of Fact No. 15

In this proceeding, SCGC contends that D.01-12-031 violates section 1705 because the CPUC purportedly did not make basic findings to support its ultimate determination in factual finding No. 15 that “[t]he time is ripe to adopt a system of FAR for [S]outhern California.” (San Diego Gas & Elec. Co., supra, [2006 WL 3858043 at p. *67].) SCGC asserts that D.01-12-031 is therefore invalid under the rationales of California Motor Transport Co. v. Public Utilities Com. (1963) 59 Cal.2d 270, Greyhound Lines, Inc v. Public Utilities Com. (1968) 65 Cal.2d 811, and California Manufacturers Assn. v. Public Utilities Com. (1979) 24 Cal.3d 251. We disagree and conclude that the CPUC made sufficient findings on the issues material to the decision.

In California Motor Transport Co. v. Public Utilities Com., supra, 59 Cal.2d 270, a trucking company applied for a certificate of public convenience to extend its operating authority as a highway common carrier. (Id. at p. 271.) The CPUC approved the application upon a single finding of “public convenience and necessity.” (Ibid.) The Supreme Court ruled that this single finding on the ultimate issue was insufficient and did not comply with section 1705. The court explained that the CPUC decision did not set forth or resolve the basic facts upon which the ultimate finding was based. (California Motor Transport Co. v. Public Utilities Com., supra, at p. 273.) The court explained that the ultimate finding of public convenience and necessity was so general that, without more, a reviewing court would have to guess as to how the decision was reached. (Id. at p. 274.) In addition, such a general finding did not permit the opposing parties to prepare for review or have the satisfaction of knowing why they lost. (Ibid.) Finally, the court explained that “[t]here is no assurance that an administrative agency has made a reasoned analysis if it need state only the ultimate finding of public convenience and necessity.” (Id. at p. 275.)

In Greyhound Lines, Inc v. Public Utilities Com., supra, 65 Cal.2d 811, the CPUC issued an order directing Greyhound to institute peak-hour commutation service between certain cities. (Id. at p. 812.) The CPUC based this order upon the finding that “ ‘[t]he public interest requires the establishment’ ” of the service. (Id. at p. 813.) The Supreme Court concluded: “The ultimate finding of public interest, like that of public convenience and necessity, does not meet the requirement of section 1705.” (Ibid.) The Supreme Court annulled the order for failure to comply with section 1705. (Greyhound Lines, Inc v. Public Utilities Com., supra, at p. 813.)

In California Manufacturers Assn. v. Public Utilities Com., supra, 24 Cal.3d 251, the CPUC granted rate increases to SoCalGas and SDG&E, which sought the increases to off-set the rising price of natural gas. (Id at pp. 254-255.) The CPUC “established a five-tier inverted rate design for residential service for the summer, providing that high priority nonresidential usage would be charged at the highest residential tier and that low priority or interruptible users would be charged one cent per therm more. The commission stated the rate for interruptible customers was ‘closer to the cost of alternate fuels’ and will serve as a ‘signal . . . that the hard realities of gas supply and increasing prices are close at hand. Steps by low priority users to convert to alternate fuels must be taken.’ The commission found the rates fixed reasonable, making them effective immediately.” (Id. at pp. 255-256, fns. omitted.) The petitioners there challenged the CPUC’s method of allocating the increases among the utility users. (Id. at p. 255.)

The Supreme Court held that the CPUC findings did not comply with section 1705. (California Manufacturers Assn. v. Public Utilities Com., supra, 24 Cal.3d at p. 259.) The Court explained: “The findings on the material issues are insufficient to justify the rate spread adopted. While the [CPUC’s] asserted justification for changing its method of spreading rate increase is conservation of natural gas resources, neither finding nor evidence exists showing the method adopted will result in conserving more natural gas than would other proposed methods. [¶] For all that appears in the record before us, the pro rata approaches suggested by the utilities or one of the plans urged by the staff might accomplish less gas usage than results from the rates adopted by the commission. As we have seen, a utility’s revenue requirement is determined by its costs, rate base, and rate of return. In allocating the revenue requirement among several groups of gas users, it is obvious that if an increase is made in the revenue requirement from one, a decrease necessarily follows in the revenue requirement allocable to others. [¶] . . . Without some expert testimony or empirical data reflecting elasticity of need and demand for the various groups, it cannot be determined which plan will result in least usage. [¶] For example, the rate spread adopted by the [CPUC] when compared to the pro rata approaches suggested by the utilities results in higher rates for nonresidential users but lower rates for residential users. The [CPUC’s] plan provides a greater incentive to conserve for nonresidential users than the other plans but lesser incentives for residential users. However, in absence of any evidence as to elasticity of demand, it is impossible to determine which plan is likely to result in least usage. Under the [CPUC’s] plan when compared to others, reduced consumption by nonresidential consumers may be more than offset by the consumption of residential consumers.” (Id. at pp. 259 -260.)

In the present proceeding, SCGC asserts that D.06-12-031 violates section 1705 because the CPUC did not make findings on certain material issues to justify what SCGC considers a fundamental change of the nature of transmission rights of natural gas set forth in finding of fact No. 15, namely, that the time was ripe to adopt a FAR system in Southern California.

Notably, in its writ petition, SCGC does not identify what additional material factual findings were absent from D.06-12-031. Instead, SCGC asserts: “The [CPUC] mischaracterizes the reliability of access to the SoCalGas system and erroneously contends that because access rights schemes of one sort or another have been considered for SoCalGas and SDG&E over the past nine years, now is the time to adopt a FAR system. The [CPUC] erroneously contends that there is currently no citygate market in [S]outhern California and erroneously concludes that because the PG&E ‘FAR-type’ system is working fine, a FAR system should be adopted for SoCalGas.”

SCGC also asserts: “The evidence relied upon by the [CPUC] is insufficient to support its conclusion that a system [of] access rights and charges should be implemented by SoCalGas and SDG&E. Indeed, the record shows that the current system is working well and that the FAR scheme as authorized by the [CPUC] will result in less flexibility than customers currently enjoy without providing any additional security.”

We reject SCGC’s assertion that D.06-12-031 violates section 1705. This case is not analogous to California Motor Transport Co. v. Public Utilities Com., supra, 59 Cal.2d 270 or Greyhound Lines, Inc v. Public Utilities Com., supra, 65 Cal.2d 811 in which the CPUC made only the single finding that the changes are issue were in the public interest. In addition, this case is not analogous to California Manufacturers Assn. v. Public Utilities Com., supra, 24 Cal.3d 251. In that case, there is no indication that the CPUC made the same level of detailed findings as in the present case. Moreover, the Supreme Court in the California Manufacturers Assn. was addressing both the sufficiency of the findings and whether the findings were supported by substantial evidence. The court stated: “[N]either finding nor evidence exists showing the method adopted will result in conserving more natural gas than would other proposed methods.” (California Manufacturers Assn. v. Public Utilities Com., supra, 24 Cal.3d at p. 259, italics added.)

Here, by contrast, the CPUC’s findings are detailed and address the material issues leading to the decision to implement the FAR system in Southern California. In fact, the findings show that the CPUC concluded:

● There is a difference between upstream capacity and the “takeaway” delivery capacity on the SoCalGas/SDG&E transmission system which can create problems.

● Under the prior system, only end-use customers can transport gas on the SoCalGas/SDG&E transmission system.

● SoCalGas must allocate available capacity on a daily basis.

● The upstream pipelines allocate their capacity under FERC-established priorities.

● The current system creates only “interruptible” or fluctuating access.

● Shippers’ natural gas can be pro-rated and receipt points constrained under the current system.

● The same basic FAR system of tradable rights adopted in D.06-12-031 has functioned well in Northern California.

● While capacity constraints have not been a significant problem during the two years prior to D.06-12-031, this does not mean that the problems have been eliminated.

● SE LNG supplies flowing in Southern California and other changes in the natural gas market may cause constraints to occur again.

● Under the current system, end-use customers face uncertainty over whether their gas will flow through a constrained receipt point.

● The FAR system will provide customers with flexibility and will result in a new citygate market in Southern California.

● The FAR system will provide greater certainty that natural gas can be delivered to Southern California which will encourage long-term gas supply contracts.

● Concerns about complexity, increased costs and affiliate preferences are unwarranted.

In conclusion, these detailed findings of fact on numerous material issues support finding of fact No. 15, that the time was ripe to adopt the FAR system in Southern California. SCGC has not articulated a single finding that the CPUC failed to make to reach this ultimate conclusion. Moreover, the findings in D.06-12-031 are sufficient to provide a rational basis for judicial review, assist this court with ascertaining the principles relied upon by the CPUC and to determine whether it acted arbitrarily. In addition, the findings permit SCGC to know why it did not prevail and to prepare for rehearing or review.

2. Substantial Evidence Supports the Findings of the CPUC

SCGC contends pursuant to section 1757, subdivision (a)(4), that the CPUC factual findings are not supported by substantial evidence in light of the whole record. SCGC contends that: (1) substantial evidence does not support the finding that problems in natural gas delivery have resulted from the difference between the delivery capability of the upstream gas supplies and the takeaway capacity of the receipt points on the SoCalGas/SDG&E integrated transmission system; (2) substantial evidence does not support the finding that the FAR system will continue to provide market participants with flexible options and will result in the creation of a citygate market for Southern California; and (3) substantial evidence does not support the comparative analysis between the Northern California PG&E transmission system and the Southern California SoCalGas/SDG&E integrated transmission system. We disagree and conclude that substantial evidence does support the CPUC factual findings.

At the outset, we must note that SCGC has failed to comply with the appellate rules governing briefs in which the moving party claims that substantial evidence does not support the decision at issue. For example, SCGC did not identify the evidence in support of the CPUC decision at issue. Likewise, in its petition, SCGC did not explain why that evidence did not constitute substantial evidence. (Road Sprinkler Fitters Local Union No. 669 v. G & G Fire Sprinklers, Inc. (2002) 102 Cal.App.4th 765, 782; Sprague v. Equifax, Inc. (1985) 166 Cal.App.3d 1012, 1027-1028.) The briefing supplied by SCGC is deficient. This court could have exercised its discretion to conclude that SCGC waived any substantial evidence assertions. Accordingly, we could have summarily denied the writ petition. (Southern Cal. Edison Co. v. Public Utilities Com., supra, 128 Cal.App.4th at p. 9 [“Thus, the court need not grant a writ if the petitioning party fails to present a convincing argument that the decision should be annulled.”].) Instead, in the interests of justice, we set forth the evidence showing that the CPUC’s factual findings were in fact supported by substantial evidence.

In Road Sprinkler Fitters Local Union No. 669 v. G & G Fire Sprinklers, Inc., supra, 102 Cal.App.4th at p. 782, the court explained: “A reviewing court begins with the ‘ “presumption that the record contains evidence to sustain every finding of fact.” ’ [Citation.] To overcome the trial court’s factual findings, G & G must ‘ “demonstrate that there is no substantial evidence to support the challenged findings.” . . . A recitation of only defendants’ evidence is not the “demonstration” contemplated under the above rule. [Citation.] Accordingly, if . . . “some particular issue of fact is not sustained, [defendants] are required to set forth in their brief all the material evidence on the point and not merely their own evidence. Unless this is done the error is deemed to be waived.” ’ [Citation.] G & G sets forth only its own evidence, ignoring the trial court’s findings and the evidence in support of those findings. It has therefore waived its substantial evidence claim.”

Specifically, the record contains substantial evidence, which supports the CPUC’s factual findings regarding the problems associated with capacity allocation, the creation of a citygate market, and the comparisons between the PG&E system and the Southern California system. Substantial evidence supports the CPUC’s findings that:

● The mismatch between upstream capacity and the SoCalGas/SDG&E takaway capacity can create problems in gas delivery.

● Gas deliveries are interruptible and pro-rated when capacity is constrained.

● The two-year absence of constraints on delivery does not mean that the problem was eliminated.

● With SE LNG expected to arrive and other gas market changes, receipt point constraints may occur at other receipt points.

● Under the current system, end-use customers face uncertainty over whether their gas will flow through a constrained receipt point.

● The FAR system will encourage the creation of a city gate market.

● The system of tradable rights has functioned in Northern California.

Specifically, Michael Alexander (Alexander) of SCE testified that in the absence of the FAR system, the natural gas market did not have “discipline” or “certainty.” He also testified that there is a premium paid for such uncertainty. He further testified that in the absence of the FAR system, an end-use customer would “take a wild gamble” that they would get their gas into the system, but with FAR, the customer would have an extra level of surety that its gas would flow. He also testified that in the current system, he has “seen traders have to scramble when there was a problem getting gas to a particular receipt point and they have discovered that the gas that they wanted to bring in is not available and they had to both sell the gas and obtain substitute supplies.” Thus, Alexander’s testimony supports findings of fact Nos. 7, 9 and 20.

Real Parties assert and SCGC does not dispute that Alexander is a representative of SCE. The record, however, does not establish Alexander’s position with SCE.

Alexander testified: “Well, today, where there [are] no firm rights [in] the system, the end[-]use customer has to pretty much take a wild gamble that they will be able to bring their gas in at all, that they won’t be edged out by others, certainly within the zone if not necessarily at the same receipt point. Under the firm access rights proposals as we’ve been talking about them, the customer would have surety, once he had obtained firm access rights, not until he obtained them, but he would be given an extra level of surety that his gas would be able to flow, and therefore, he’d have more reliable knowledge that he would get that capacity in. It would take more time, but there would be the advantage of additional reliability to compensate.”

Likewise, in prepared testimony, Steve Watson (Watson), the capacity products staff manager for SoCalGas and SDG&E, explained the mismatch between the potential upstream supply delivery and the existing intrastate transmission redelivery capacity. He noted that this mismatch will increase as new supply projects are developed. Watson testified: “This mismatch can create uncertainty for suppliers and their customers about whether the full supply from a particular source will be delivered. Under current rules, this mismatch makes it difficult to create a firm connection between a supplier and its [S]outhern California end-use customer that is reliable every day of the year. This testimony supports finding of fact No. 19 regarding receipt point constraints which may result from the addition of new gas supplies.

The record contains testimony from Thomas Beach acknowledging that a company called Coral and real party SE LNG “have funded an expansion of the Otay Mesa receipt point that would permit 400 million cubic feet a day of gas to be redelivered on a displacement basis.”

SCGC asserts that the CPUC must wait for significant constraints to occur before it may adopt the FAR system. We reject this assertion. SCGC has provided no authority for this proposition. Moreover, on this record, we will not limit the discretion of the CPUC to anticipate changes that are likely to occur in the natural gas market and to fashion a remedy to accommodate the changing conditions. In addition, the CPUC also instituted FAR not just to address potential constraint problems, but also to encourage the formation of long-term supply contracts to bring greater certainty to the natural gas market.

Watson further testified: “If a particular single interstate pipeline has contracted capacity with its shippers for volumes that exceed the physical take-away of a specific SoCalGas receipt point (e.g. Kern River Pipeline Company (Kern River) at Wheeler Ridge), it is the upstream pipeline shippers’ contractual rights that define whose gas flows on that day. SDG&E and SoCalGas believe that [the CPUC] would rather have California end-users, or their agents, control which supplies enter the SDG&E and SoCalGas system under this circumstance.”

Watson also testified that the mismatch between delivery and takeaway capacity results in pro-rationing. About this he testified: “Pro-rationing frustrates both suppliers and end-users, creates confusion in the marketplace, and does not necessarily allow the lowest-cost gas to get to end-use markets.”

About the FAR system, Watson testified: “Under a system of firm access rights, it will be the holders of firm access rights who will determine which supply flows from each supplier on each day within each zone. Holding the firm receipt point rights that flow through the Wheeler Ridge Zone, for example, will give that customer the ability to determine the choice of supply daily. Along with the increased choice of supply will come increased certainty of flow. Firm receipt point rights will assure the customer that 100% of its designated gas flow will flow 100% of the time. Finally, firm access rights move the control of the SoCalGas receipt points from the FERC-regulated interstate pipelines to the utilities in California and their customers.”

Watson testified about an alternative solution to resolve the existing capacity and take-away mismatch: “An alternative way to eliminate the supply uncertainty associated with the status quo would be to expand the take-away capacity of SoCalGas’ backbone transmission system to match or even exceed the peak, simultaneous delivery capacity of all upstream pipelines through additional investment in the SDG&E and SoCalGas backbone transmission system. But the cost of expanding SoCalGas’ receipt point take-away capability in this manner . . . would be extremely expensive (greater than $857 million according to Mr. Bisi’s December 2005 testimony in R.04-01-025), and is, in SoCalGas’ opinion, unnecessary to do at ratepayer expense. SoCalGas already has total transmission delivery capacity that exceeds total end-use demand to a significant degree (a ‘slack capacity factor’).” (Fn. omitted.)

Watson also testified that the FAR system would be preferable to new gas suppliers because the FAR system would put new gas supplies on a level playing field with existing supplies; the FAR system would permit the expansion of the transmission system and the establishment of new receipt points; and new suppliers and customers could obtain long-term access to the SoCalGas/SDG&E system to justify large capital investments. This testimony supports finding of fact No. 27 because shows that long term contracts will justify large capital outlays.

Thomas Beach (Beach), a representative of real party CMTA, orally testified about the current system as follows: “[T]hat kind of a system where everybody is . . . chasing the cheapest price supply encourages people to rely a hundred percent on the daily spot market for the gas supplies rather than looking at options like longer term supply arrangements which could provide greater price stability. [¶] If you are always chasing the cheapest spot price on a particular day, then you are never going to have a system that provides shippers with the assurance that they could move a longer term supply to their burnertips on a reliable basis.”

Real parties assert and SCGC does not dispute that Beach was a representative of CMTA. His position with CMTA is not identified in the record.

Beach acknowledged that some of the problems with the present system had been ameliorated, but that the FAR system was superior because “[i]t’s comprehensive.” He testified that the FAR system “uses capacity rights that are freely tradable. It encourages equal access and it will expand the gas procurement flexibility for customers by creating a citygate market.” He noted: “Well, I think it’s better to have a comprehensive system that can work at any receipt point and that applies equally to all receipt points rather than the system of Band-Aids that we have today.” This testimony supports finding of fact Nos. 26 and 27 concerning the positive attributes of creating a citygate market and the long-term benefits of long term contracts.

Beach described the current Wheeler Ridge receipt point allocation methodology as a “use-it-or-lose-it” approach. He explained that under the current system, a shipper’s access rights are based upon the flow the from the day before. Thus, if there was no flow the prior day, the shipper may not have access rights. About this problem, SoCalGas/SDG&E witness Watson testified that at Wheeler Ridge, sometimes natural gas suppliers or shippers may find more attractive alternative markets. In the interim, however, other suppliers might fill up the available shipping space. When a shipper comes back, it may be cut-off from access to the Wheeler Ridge receipt point and have to wait for the window to re-open.

Beach also testified that the price of natural gas is impacted “by whether the supply can flow into the SoGalGas system on an interrupted basis, because it costs money to go to another receipt point, line up another supply, and bring that into the SoCal system when your original supply can’t get in.” This testimony supports finding of fact No. 20 because it described how uncertainty under the current method increases gas prices.

The record indicates that the current allocation system at the Wheeler Ridge receipt point had available access during the two-year time period preceding the hearings. PG&E witness Roger Graham (Graham), testified, however, that this was not the case in 2003 and 2004. He testified that the favorable conditions in 2005 were due to the mild summer. This testimony supports finding of fact No. 18 because it shows that the constraints on the system have not been eliminated.

Real parties assert, and SCGC does not dispute that Graham was a representative of PG&E. His position with PG&E is not identified in the record.

Finally, the prepared testimony of SoCalGas/SDG&E witness Watson constitutes substantial evidence that adoption of the FAR system will result in the creation of a citygate market. He testified: “Additionally, a citygate market will develop with a system of FAR similar to the citygate market on the PG&E system. A developed citygate market will enhance customer flexibility and potentially reduce costs to end-use customers.”) Watson’s testimony supports findings of fact Nos. 26 and 27.

The record also contains substantial evidence that the creation of a citygate market will result in more options for gas customers, thus supporting Finding of Fact Number 26. Witness Beach testified that under the current system, a customer pays a single price at the border market. According to Beach, the creation of a citygate market will result in additional pricing points, and allow customers to shop around among the lower cost receipt points. Likewise, witness Graham testified that breaking the border price into separate markets will create more transactions and more competition that what exists in the present system.

Finally, finding of fact No. 16 states that the same basic FAR system has functioned in Northern California. Substantial evidence supports this finding of fact. Witness Beach testified that the SoCalGas/SDG&E transmission system is the same sort of high pressure, large diameter system used in Northern California. He testified: “This works today on the PG&E system where you have a PG&E Topock price and it is exactly the same situation.” Beach further testified: “I think the difference is that on SoCal’s system, the hub is a little bigger and the spokes are a little shorter than in Northern California. But I think the essential geography and configuration of both systems is very similar.”

Moreover, the CPUC decision at issue shows that the CPUC did not adopt the FAR system solely because it worked well in Northern California. On the contrary, In D.06-12-031, the CPUC stated: “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.” (San Diego Gas & Elec. Co., supra, [2006 WL 3858043 at p. *32].)

In conclusion, the CPUC’s findings are supported by substantial evidence.

3. The “Set-Asides” Were Reasonable Under the Circumstances

SCGC asserts that the CPUC’s authorization of certain set-asides of firm receipt point capacity for specific customers and customer classes is arbitrary and capricious and unduly discriminatory. SCGC claims that the CPUC failed to provide a systematic rationale for establishing the set-asides and that certain individual set-asides were granted on an ad hoc basis. We disagree.

As described below, in D.06-12-031, the CPUC set forth a systematic rationale for establishing the set-asides. It is undisputed that the purpose of the set-asides is to match as closely as possible each customer’s commitment to upstream capacity, production capacity, interstate capacity and intrastate capacity. D.06-12-031 implements this policy as described below.

Specifically, in the three-step open season process, during Step 1, FAR rights are allocated for retail and wholesale core customers, as well as Core Transportation Aggregators (CTA’s), holders of certain long term contracts, and California gas producers. (San Diego Gas & Elec. Co., supra, [2006 WL 3858043 at p. *6].) The Step 1 set-aside is for a period of three years. (Ibid.) In the decision, the CPUC explained: “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. . . . [¶] 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. . . . 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.” (Ibid.)

Step 2 of the three step open season process allows bids from end-use customers or their designated agents for up to 75% of the capacity at each existing receipt point, minus any capacity that has been already taken as a set-aside. (San Diego Gas & Elec. Co., supra, [2006 WL 3858043 at p. *7].) The CPUC explained in D.06-12-031 that “[t]he end-user’s maximum biding 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. 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.” (Ibid., fn. omitted.) Like Step 1, the contract period for Step 2 capacity is also three years. (Ibid.)

Finally, Step 3 of the FAR open season allows an open season for the remaining receipt point capacity, as well as expansions at receipt points and new receipt points that become available prior to each open season cycle. (San Diego Gas & Elec. Co., supra, [2006 WL 3858043 at p. *8].) D.06-12-031 further provides: “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. (Ibid) The contract term is for three to twenty years. (Id., at p. *52].)

Having reviewed D.06-12-031 and the CPUC decision denying rehearing, D.07-06-003, we conclude that the three-step open season process is not arbitrary and capricious, but instead that the decisions set forth a systematic rationale for establishing the set-asides.

We also conclude that SCGC has failed to show that the individual set-asides were discriminatory and granted on an ad hoc basis. In D.06-12-031, the CPUC granted set-asides for retail and wholesale core customers, including SoCalGas and SDG&E, as well as CTA’s, holders of certain long-term contracts, and California gas producers. (San Diego Gas & Elec. Co., supra, [2006 WL 3858043 at p. *6].)

With respect to CTA’s, in D.06-12-031, the CPUC explained: “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. . . . 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.” (San Diego Gas & Elec. Co., supra, [2006 WL 3858043 at p. *7].)

With respect to holders of long term contracts, in D.06-12-0312, the CPUC explained: “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.” (San Diego Gas & Elec. Co., supra, [2006 WL 3858043 at p. *7].)

With respect to California Gas Producers, in D.06-12-0312, the CPUC explained: “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 . . . . The California producer set-aside on Line 85 is estimated at 140 MMcfd, and 100 MMcfd on the Coastal transmission zone.” (San Diego Gas & Elec. Co., supra, [2006 WL 3858043 at p. *7].)

The CPUC, however, rejected set-asides for noncore customers with long term upstream contracts. SCGC points out, however, that the CPUC granted FAR set-asides to non-core customers with upstream contracts, including Exxon Mobil, Occidental of Elk Hills (OEHI), and SE LNG developers. SCGC asserts that the CPUC granted all requests for set-asides to accommodate upstream commitments, except the request granted by SCGC. SCGC asserts that this was patently discriminatory.

We reject this assertion. The CPUC has broad discretion to differentiate among customer classes with regard to rates and service classifications if there is “a reasonable relationship between the classifications drawn and the purpose for which they are made.” (Wood v. Public Utilities Commission (1971) 4 Cal.3d 288, 294 (Wood).)

In this case, the CPUC set out specific facts and circumstances which warranted the grant of individual set-asides. SCGC points to no evidence of special facts and circumstances to justify similar set-asides for its constituents. In the words of the Wood court, the CPUC established a reasonable basis for treating SCGC’s constituents differently from Exxon Mobile and OEHI.

For example, with respect to OEHI, in D.06-12-031, the CPUC explained: “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.” (San Diego Gas & Elec. Co., supra, [2006 WL 3858043 at p. *46].)

In addition, in D.06-12-031, the CPUC set forth its rationale for denying a set aside to the constituents of SCGC: “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. . . . 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.” (San Diego Gas & Elec. Co., supra, [2006 WL 3858043 at p. *47].)

As noted, SCGC failed to demonstrate any special circumstances to justify similar set-asides for its constituents. In addition, SCGC failed to show that the CPUC’s foregoing rationale for denying set-asides to its constituents was factually incorrect. In other words, SCGS has failed to show that there would be available capacity in Steps 2 and 3 to end-users and other market participants if its constituents received set-asides.

Moreover, CMTA witness Beach provided the following prepared rebuttal testimony where he explained the underlying justification for set asides. Beach testified: “In my view, Step 1 set-asides are reasonable for two reasons: first, to meet the needs of high-priority core customers and, second, to allow SoCalGas to respect the long-term contractual commitments that it has made to California producers (via firm access agreements) and certain specific noncore customers (via long-term transportation contracts) to provide such customers with firm access to the SoCalGas system at specified receipt points. The [CPUC] has found that core loads should be served primarily with firm interstate pipeline contracts within a specified capacity planning range. It is reasonable that the SoCalGas/SDG&E core procurement groups should hold the firm interstate capacity (FARs) needed to deliver these interstate supplies to high-priority core customers. It is also sound public policy to ensure that SoCalGas respects the ‘benefit of the bargain’ that it has made under [CPUC]-approved long-term transportation contracts that provide the contract holder with specific firm receipt point rights. However, the utility has made no such long-term commitments to other noncore customers that hold interstate pipeline capacity, but that take regular tariff service on the SoCalGas system. As a result, such customers should not receive a set-aside of FARs.” (Fns. omitted.)

Beach continued: “SCGC has not provided any details concerning how its proposed ‘noncore’ set-aside might work. SCGC does not specify the likely size of such set-asides, nor how they would affect the remaining capacity available to noncore customers in Steps 2 and 3 of the open season. Given the interstate capacity holdings of SCGC members alone, as shown in Table 1, a noncore set-aside could be very large. SCGC has not proposed how SoCalGas would administer noncore set-asides, including important details such as the minimum term of the interstate capacity contract that would be required to qualify for such a set-aside. In contrast, SoCalGas’ proposed Step 1 set-asides are detailed fully in its testimony, including the amounts of FARs that would be reserved in Step 1 at each receipt point. The [CPUC] should not approve SCGC’s Step 1 set-asides unless the market has a complete understanding of the impacts of those reservations on the FAR program.”

SCGC failed to cite Beach’s testimony. SCGC did not explain why Beach’s testimony fails to support the CPUC decision to deny set-asides to SCGC’s constituents. In conclusion, SCGC has failed to show that the CPUC decision to deny it a FAR set-aside was unreasonable or discriminatory.

DISPOSITION

The Decisions under review are affirmed. The petition for a writ of review is denied.

We concur: KLEIN, P. J., CROSKEY, J.

APPENDIX A

B202987

Below is the CPUC’s description of how the SoCalGas allocated capacity on its transmission system prior to implementation of the FAR 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.” (San Diego Gas & Elec. Co, supra, [2006 WL 3858043 at pp. *4-5].)

APPENDIX B

B202987

A. Factual Findings

“1. The origin of this proceeding can be traced back to R.98-01-011 wherein we considered and identified appropriate reforms to the natural gas market structure in California.

“2. D.99-07-015 acknowledged that PG&E’s Gas Accord market structure should be considered for SoCalGas.

“3. D.01-12-018 adopted the CSA, which called for a system of firm tradable transmission rights on SoCalGas’ backbone transmission system, the unbundling of the backbone costs from transportation rates, and an at-risk rate structure for the recovery of the backbone transmission costs.

“4. D.04-04-015 adopted the tariffs to implement D.01-12-018, but due to another proceeding, D.04-04-015 was stayed and extended in D.04-09-022 until further notice.

“5. D.04-09-022 directed SDG&E and SoCalGas to file an application regarding their system integration and FAR proposals.

“6. The system integration issue was addressed in the first phase of this proceeding in D.06-04-033.

“7. 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 integrated transmission system, problems in the delivery of gas can result.

“8. Under the current system of allocating capacity on the SDG&E and SoCalGas transmission system: (1) end-use customers are the only ones who can transport gas; (2) SoCalGas allocates the available receipt point capacity to the upstream pipelines daily; and (3) the upstream interstate pipelines allocate the capacity among their shippers using their FERC-approved capacity allocation rules.

“9. The current system of capacity allocation can result in a situation where access to the system is available only on an interruptible basis, shippers’ gas supplies are pro-rated, and receipt points are constrained.

“10. SDG&E and SoCalGas’ FAR proposal would allocate access rights to the capacity at a particular receipt point on the integrated transmission system to various market participants using a three-step open season process.

“11. The two major differences between the unbundled FAR proposal and the FAR proposal is the unbundling of backbone transmission costs from transmission rates, and putting SDG&E and SoCalGas at-risk for the recovery of the backbone transmission costs.

“12. DRA’s proposal allocates FAR to end-use customers based on the current allocation of intrastate gas transmission costs in the last BCAP, excluding the California gas production receipt points.

“13. The Joint Proposal addresses a process for granting scheduling rights for new or expanded receipt point capacity, and a process for granting scheduling rights for new or expanded receipt point capacity in the Southern transmission zone.

“14. This phase of the proceeding revisits many of the same issues that were considered when the CSA was adopted, and the various parties continue to disagree on what kind of market structure is best for [S]outhern California.

“15. The time is ripe to adopt a system of FAR for [S]outhern California.

“16. The basic underlying system of firm tradable transmission rights has worked and functioned well in [N]orthern California.

“17. [SE LNG] project sponsors, as well as others, seek assurance that their gas can be delivered into the receipt points on the SDG&E and SoCalGas transmission systems.

“18. 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.

“19. With the possibility of [SE LNG] supplies flowing into [S]outhern California, and other changes in the gas market, receipt point constraints may occur again at other receipt points.

“20. Under the current system, end-users face uncertainty over whether their gas will flow through a constrained receipt point.

“21. The uncertainty over whose gas will flow affects the procurement decisions of end-users.

“22. DRA’s proposed allocation method does not provide shippers and marketers with any firm capacity, is likely to result in market participants spending a lot of time to match their needs, and is likely to lead to confusion.

“23. The Joint Proposal is limited to creating scheduling rights for new or expanded receipt point capacity, and does not establish a system of FAR for existing receipt points on the transmission system.

“24. The capacity allocation proposals considered in this decision vary from the capacity allocation method contained in the CSA that was adopted in D.01-12-018.

“25. According to its terms, the CSA was terminated on August 31, 2006.

“26. The FAR proposal will continue to provide market participants with flexible options and result in the creation of a citygate market for [S]outhern California.

“27. The adoption of the FAR proposal provides certainty to FAR holders that their gas can be delivered from the receipt point to the citygate, which in turn will encourage parties to enter into long-term gas supply contracts.

“28. The concerns regarding the FAR proposal’s complexity, increased costs, and affiliate preference are unwarranted.

“29. The facts addressed in the Union Pacific Fuels decision are different and distinguishable from the reservation charge that would be assessed on FAR holders.

“30. The transmission system has been paid for in rates by the end-users of SDG&E and SoCalGas.

“31. The FAR reservation charge provides the FAR holder with access to the transmission system.

“32. It is appropriate that shippers and marketers, who have not paid for the cost of the transmission system, pay for a share of the transmission facilities through the reservation charge.

“33. The at-risk provision operates in conjunction with the unbundling of the backbone transmission costs and the 15.75 cents per Dth reservation charge.

“34. A reservation charge lower than the unbundled FAR proposal rate of 15.75 cents per Dth is needed to stimulate participation for holding a FAR.

“35. A cost-of-service FAR charge based on backbone transmission costs will send the appropriate price signals to users of the system.

“36. A FAR system that has a lower unbundled reservation charge and no at-risk provision will provide a baseline for determining whether future adjustments to the FAR system are needed.

“37. Putting SDG&E and SoCalGas at risk would act as an incentive to maximize throughput on their system, which is contrary to the energy efficiency and conservation goals, and is not appropriate at this time.

“38. It is appropriate to unbundle the FAR reservation charge of five cents per Dth from the end-user’s bundled transmission rate, and that the credit-back mechanism not be adopted.

“39. The parties proposed a number of modifications to the FAR proposal.

“40. The citygate pooling service allows for the aggregation and disaggregation of natural gas at the citygate, and creates a pricing point for customers to buy and sell gas.

“41. SDG&E and SoCalGas propose to offer firm backhaul service and interruptible off-system service through backhaul.

“42. Off-system service provides gas suppliers with another market to sell their gas.

“43. The peaking rate tariff applies to gas transportation service provided to any noncore customer who bypasses SoCalGas, in part or in whole.

“44. The multi-unit EG provision used to be in the RLS tariff, but was eliminated when the peaking rate tariff was adopted.

“45. The evidence presented in this proceeding has not changed the circumstances behind the adoption of the RLS and peaking rate tariff.

“46. If the peaking rate is eliminated, the remaining ratepayers will have to pay higher rates because they will bear the costs that the departing customers would have paid.

“47. Without the peaking rate, a bypassing customer who calls on SoCalGas for service would only pay the same rate for gas as those customers who remain on the system.

“48. The argument that the peaking rate has discouraged electric generators from siting within SoCalGas’ service territory is unpersuasive.

“49. D.06-04-033 described why the peaking rate does not apply if SDG&E obtains gas at the Otay Mesa receipt point.

“50. The evidence does not support the reinstatement of the multi-unit EG provision as part of the peaking rate tariff.

“51. The last complete adjudication of the BCAPs for SDG&E and SoCalGas occurred in D.00-04-060.” (San Diego Gas & Elec. Co., supra, [2006 WL 3858043 at p. *67].)

B. Conclusions of Law

“1. Due to 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, the current system of allocation should be replaced by a system of FAR.

“2. DRA’s proposal is not a practical solution for allocating capacity to market participants and should not be adopted.

“3. SDG&E and SoCalGas should incorporate the unbundling concept from the unbundled FAR proposal for the FAR reservation charge of five cents per Dth, and the features of the Joint Proposal that we adopt, as described in this decision, into the adopted FAR system.

“4. SDG&E and SoCalGas should perform a cost study of the backbone transmission system prior to filing the next BCAP, and the [CPUC] should adopt a new cost-based FAR charge based on the results of the next BCAP.

“5. The conversion of the four types of scheduling right situations into the three-step process of the adopted FAR system, as described in the decision, are appropriate and consistent with prior decisions.

“6. D.01-12-018 and D.04-04-015 are now moot as a result of today’s adoption of the FAR system.

“7. The FAR reservation charge is not unlawful under the holding of Union Pacific Fuels.

“8. The credit-back mechanism is not discriminatory, and 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. SDG&E and SoCalGas should be authorized to establish a balancing account so that they are not at risk for any under-recovery of the unbundled FAR reservation charge revenues, and any over-recovery is refunded to ratepayers.

“10. SDG&E and SoCalGas’ FAR proposal, as modified by today’s decision, should be adopted as the model for the FAR system, and SDG&E and SoCalGas should incorporate the adopted modifications to the FAR proposal, as described in this decision, into the adopted FAR system.

“11. There are no provisions in the Continental Forge or SCE settlements that prevent us from adopting the FAR proposal as the model for the FAR system.

“12. SDG&E and SoCalGas should be authorized to establish the FAR Memorandum Account to track and recover the costs of implementing the FAR system and the other services.

“13. SDG&E and SoCalGas should file an AL to implement the tariffs and services needed for the FAR system.

“14. A review process to assess how the FAR system is working, and whether any changes or modifications are needed, should be initiated by application 18 months after the initial open season has concluded.

“15. SDG&E and SoCalGas’ proposal to offer a pooling service should be approved, and an AL should be filed to implement the tariff and services needed for the pooling service.

“16. To the extent the costs of implementing the pooling service are not included in the FAR system implementation costs, SDG&E and SoCalGas should be allowed to track and recover from all ratepayers the reasonable costs of implementing this service up to a maximum of $500,000.

“17. SDG&E and SoCalGas’ proposal to offer off-system delivery service to PG&E, as modified by our discussion in this decision, should be approved, and an AL should be filed to implement the tariff and services needed for the off-system delivery service.

“18. The use of SoCalGas’ transmission facilities to transport gas to points outside of California raises FERC jurisdictional issues, and has operational ramifications for intrastate transmission.

“19. SDG&E and SoCalGas should be permitted to file an application to offer off-system service to pipeline interconnections other than PG&E no earlier than May 1, 2008.

“20. The SoCalGas peaking rate tariff should continue in effect, and the multi-unit EG provision should not be included as part of the peaking rate tariff.

“21. SoCalGas should be ordered to propose in its next BCAP a redesign of the peaking service tariff or a total redesign of its rates to ensure that viable partial bypass can occur while allowing pipe-to-pipe competition to occur.

“22. The causes of the regulatory gap that have led to the peaking rate, including the utilities’ rate design, balancing requirements, and other factors, should be reexamined in the next BCAP, and upon closure of the regulatory gap, the peaking service tariff should expire at the conclusion of the next BCAP.

“23. SDG&E and SoCalGas should file their BCAP applications no earlier than October 1, 2007 and no later than December 15, 2007.” (San Diego Gas & Elec. Co., supra, [2006 WL 3858043 at p. *67].)

C. Order Approving the FAR System

“1. A firm access rights (FAR) system is adopted as the new gas market structure for the integrated gas transmission system of San Diego Gas & Electric Company (SDG&E) and Southern California Gas Company (SoCalGas).

“a. The adopted FAR system shall be comprised of the SDG&E and SoCalGas FAR proposal, the unbundling of the FAR reservation charge of five cents per decatherm from the end-user’s transmission rate, the adopted features of the Joint Proposal, and the adopted modifications to the FAR proposal, as described in this decision.

“b. SDG&E and SoCalGas shall incorporate all of these adopted elements into the FAR system.

“2. SDG&E and SoCalGas are authorized to offer a gas pooling service on the SDG&E and SoCalGas integrated transmission system, and an off-system delivery service to Pacific Gas and Electric Company (PG&E).

“3. SDG&E and SoCalGas shall file appropriate advice letters (AL) to implement the FAR system, the gas pooling service, and off-system delivery service to PG&E.

“a. The ALs shall contain the tariff and service offerings, and shall be consistent with, and in compliance with today’s decision.

“b. The ALs shall be filed within 45 days of the effective date of this decision. The ALs are subject to protest, and such protests shall be filed within 20 days after the ALs have been filed.

“c. SDG&E and SoCalGas shall serve the ALs by e-mail on the service list to this proceeding, as well as on interested parties who have requested notification of AL filings for SDG&E and SoCalGas.

“4. The FAR system, the gas pooling service, and the off-system delivery service to PG&E 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.

“5. SDG&E and SoCalGas are authorized to establish the FAR Memorandum Account to track and recover the costs of implementing the FAR system and the other services.

“a. To the extent the costs of the pooling service are not included in the estimate of the FAR system implementation costs, SDG&E and SoCalGas are authorized to track and recover from all ratepayers the reasonable costs of implementing the pooling service, up to a maximum of $500,000.

“6. SDG&E and SoCalGas are authorized to establish a balancing account to track and recover the difference for any under-or over-recovery of the unbundled FAR reservation charge revenues.

“7. A review process of the FAR system will be conducted to assess how the FAR system is working, and whether any changes or modifications to the FAR system are needed.

“a. SDG&E and SoCalGas shall file an application 18 months after the initial open season has concluded, and shall include the type of information described in this decision.

“8. SDG&E and SoCalGas shall be permitted to file an application, no earlier than May 1, 2008, to offer off-system service to pipeline interconnections other than PG&E.

“a. The application shall include the type of information described in this decision.

“9. The SoCalGas peaking rate tariff shall continue in effect, and the proposal to include the multi-unit electric generation provision into the peaking rate tariff is not adopted.

“a. In its next Biennial Cost Allocation Proceeding (BCAP), SoCalGas shall include a proposal for a total redesign of its rate consistent with the discussion regarding closing or minimizing the regulatory gap.

“b. Upon closing of the regulatory gap, the existing peaking service tariff shall sunset at the conclusion of the next BCAP.

“10. SDG&E and SoCalGas shall file their BCAP applications no earlier than October 1, 2007 and no later than December 15, 2007. a. The BCAP applications shall include a cost study of the backbone transmission system and a proposal for a new cost-based FAR reservation charge.

“11. Application 04-12-004 is closed.” (San Diego Gas & Elec. Co., supra, [2006 WL 3858043 at pp. *68-69].)

With respect to Exxon Mobile, in D.06-12-031, the CPUC explained: “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. 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.” (San Diego Gas & Elec. Co., supra, [2006 WL 3858043 at p. *47, fn. omitted].)

In its briefing, SCGC has failed to set forth, explain or refute the CPUC’s stated reasons and the evidence cited for granting set-asides to OEHI and Exxon Mobile. It has provided no explanation for why its constituents should be treated similarly. Based upon this failing, SCGC has waived any assertions of error with respect to the granting of the set-asides. (See Road Sprinkler Fitters Local Union No. 669 v. G & G Fire Sprinklers, Inc., supra, 102 Cal.App.4th at p. 782.)


Summaries of

Southern California Generation Coalition v. California Public Utilities Commission

California Court of Appeals, Second District, Third Division
May 19, 2008
No. B202987 (Cal. Ct. App. May. 19, 2008)
Case details for

Southern California Generation Coalition v. California Public Utilities Commission

Case Details

Full title:SOUTHERN CALIFORNIA GENERATION COALITION, Petitioner, v. CALIFORNIA PUBLIC…

Court:California Court of Appeals, Second District, Third Division

Date published: May 19, 2008

Citations

No. B202987 (Cal. Ct. App. May. 19, 2008)