Decision PROPOSED DECISION OF COMMISSIONER BILAS AND
ALJ WEISSMAN  (Mailed 5/25/99)

BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA

Rulemaking on the Commission’s Own Motion to Assess and Revise the Regulatory Structure Governing California’s Natural Gas Industry.
	
Rulemaking 98-01-011
(Filed January 21, 1998)	

(See Appendix A for List of Appearances.)

ORDER IDENTIFYING PROMISING
OPTIONS FOR FURTHER STUDY

I.	Summary of Promising Options
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.  We seek to identify the services for which the public interest suggests the need for greater competition and determine the steps that the Legislature and this Commission must take to facilitate healthy competition.
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.  Once we have considered the costs and benefits of various options, we will prepare a report to the Legislature setting forth the changes that we propose be undertaken.
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.
We would implement more vigorous consumer protection rules for the benefit of smaller customers and then remove limits that currently constrain participation in the core aggregation programs.  We would continue to hold the local distribution companies responsible for providing safe service on both sides of the customer meter, while creating options for consolidated billing for customers who choose to take service from competitive providers.
We would extend certain improvements recently implemented in the Pacific Gas and Electric Company (PG&E) service territory to ensure that they remain in effect beyond the limits of the Gas Accord and enact similar reforms in the Southern California Gas Company (SoCalGas) service territory.  These improvements include the creation of tradable access rights 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.
Key to this process will be our efforts to ensure that shippers are better informed of the status of the utility delivery and storage systems and the prices of various service components as well being given greater flexibility to package utility and competitive services to suit their needs.  Better informed participants are critical both to the functioning of an efficient marketplace and to effective oversight of utility market practices.  We hope that the market participants will work aggressively, within the boundaries that we set forth in this order, to implement significant improvements in the provision of real-time data.  The offering of unbundled services will allow customers to become better informed of the cost of various service components, while creating a greater opportunity for competing providers who offer attractive services at low prices to win new customers.
We present the observations contained in this decision to all stakeholders in the hopes that they will use them as a guide in their pursuit of a comprehensive settlement.  We are setting aside a 60-day period after the adoption of this order so that parties may attempt to develop a consensus plan for the evolution of the natural gas industry in California.
We also are establishing a schedule and procedures to be followed in the event that stakeholders do not achieve  a comprehensive settlement.  We will seek, from all participants, an analysis of costs and benefits, including safety, consumer protection and labor impacts, related to various change options.  We plan to consider the results of the analysis and then prepare a report to the Legislature proposing specific changes.
A stakeholder-generated solution is preferred, as long as it is consistent with the law, in the public interest, and reasonable in light of the information available to the Commission.  We prefer such a solution because those who participate in the natural gas marketplace are in the best position to understand and accommodate underlying interests.  Thus, we encourage parties to undertake an effort to design an answer to the questions raised in this rulemaking proceeding, subject to the following conditions.
First, we ask stakeholders to dedicate their efforts to reach an agreement within the 60 days.  We will establish a deadline 30 days thereafter for the submission of cost/benefit testimony.  Second, it is critical that any such agreement reflect an appropriate balance of the interests of all stakeholders affected by the outcome in this proceeding.  For this reason, no interested parties should be excluded from the negotiating process.  All interested parties should have a place at the table either directly, or through a caucus representative.   Finally, to the extent feasible, we offer the Commission’s resources to assist in the negotiation process.  We can provide meeting space, notify participants, supply a facilitator or mediator, or furnish other similar assistance as needed.
In the decision that follows, we describe each of the most promising options in greater detail.
II.	Background
A.	Procedural History
The Commission opened Order Instituting Rulemaking (OIR) R.98‑01‑011 on January 21, 1998 to assess the current market and regulatory framework for California’s natural gas industry and to adopt reforms which emphasize market-oriented policies that will benefit all California Natural gas consumers.  The Strategic Planning Division’s report, Strategies for Natural Gas Reform:  Exploring Options for Converging Energy Markets, was attached to the Order.   The proceeding was categorized as quasi-legislative and co-assigned to Commissioner Knight and President Bilas.
The record in this proceeding is extensive.  Interested parties were invited to join the California gas utilities to comment on the report’s issues and recommendations, and respond to a list of questions attached to the OIR, by February 20, 1998.  By ruling dated February 10, 1998, ALJ Malcolm granted the request of respondent utilities to extend the deadline for filing the first set of written comments to March 23, 1998, and scheduled a full panel hearing for April 6 and 7, 1998 at 10:00 a.m. in the Commission Auditorium.  On March 17, 1998, the assigned commissioners issued a ruling that identified April 24, 1998 as the due date for reply comments, limited the full panel hearing to April 6 only, and addressed other procedural matters.
The assigned commissioners issued another ruling on April 23, 1998 directing the utilities and other parties to take various steps to assist us in our investigation of the natural gas industry.  The assigned commissioners asked parties to file Market Conditions Reports testimony by July 15, 1998 describing participants’ experiences with the utility procurement, transportation and storage services, with rebuttal testimony – or comments to the Reports for those electing not to file testimony—due August 21, 1998.   Second, the assigned commissioners asked parties to file briefs on jurisdictional issues raised by the proposals in the DSP Report.  Third, the assigned commissioners requested that parties form two working groups:  1) a Revenue Cycle Services Safety Working Group to address safety concerns related to the unbundling of meter provision and related services and report to the Commission by September 15, 1998; and 2) a Statewide Consistency Working Group to develop an inventory of significant inconsistencies in gas market structure and regulatory treatment across the State, and report to the Commission no later than September 4, 1998.  Last, they notified parties that the Commission would hold a roundtable discussion on safety issues on June 11, 1998.
On August 6, 1998, the Commission issued our first Interim Order in this rulemaking, Decision (D.) 98-08-030.  In that order, we affirmed the procedural steps taken by the assigned commissioners and stated our intention to use all the information presented to us to develop a market structure decision that would provide focus for our final determination of appropriate market structure.  Second, we articulated our goals in assessing changes to natural gas market structure.  Third, we denied without prejudice the Coalition of California Utility Employees and the Southern California Gas Workers Council (CCUE/SCGWC) motion for determination of the applicability of CEQA to this rulemaking, and clarified we would entertain subsequent motions on that subject after issuing our market structure proposal.  Finally, we identified a number of short-term steps intended to improve both our understanding of, and the operation of, the industry, including 1) directing the respondent utilities to file applications no later than February 26, 1999 identifying the functional categories to which all costs should be allocated, by service; 2) requesting the Energy Division to develop proposed consumer protection rules for the natural gas industry; 3) requiring the utilities with Core Aggregation programs to file, following Commission adoption of consumer protection rules, advice letters reflecting the tariff changes necessary to remove the threshold limits on core aggregation participation.
On August 28, 1998 the California Legislature and the Governor enacted Senate Bill (SB) 1602, creating Section 328 of the Pub. Util. Code.  That section expressly allows the Commission to investigate issues associated with the further restructuring of natural gas services, but prohibits the Commission from “enacting” any gas industry restructuring decisions prior to January 1, 2000.  It also states that any natural gas restructuring decisions for core customers issued after July 1, 1998 shall not be enforced.
In response to this legislation the Commission issued the Second Interim order in this rulemaking, D.98-10-028, on October 8, 1998.  In that order we set a new procedural schedule, including a prehearing conference, evidentiary hearings, briefs, oral argument and open comment meetings, to assist us in preparing a report to the Legislature identifying our proposed long-term market structure for the natural gas industry.  We further clarified that, in the absence of further statutory instruction, we would not adopt a final market structure policy decision before January 1, 2000.  Finally, we noted that, consistent with SB 1602, we would not require the utilities to file unbundling applications as directed in D.98-08-030.
On November 4 and December 1, 1998, President Bilas and ALJ Weissman held prehearing conferences, respectively, to discuss the format and schedule for evidentiary hearings and the scope of our market inquiry.  President Bilas subsequently issued a ruling (on December 21, 1998) that clarified the scope of our inquiry in the Market Conditions hearings and the intended procedure for our effort to produce a report to the Legislature.  Then, on January 19, 1999, President Bilas and ALJ Weissman convened two weeks of panel-style hearings to hear extensive testimony regarding the array of options and proposals for hub, storage, balancing, transmission, and core procurement services.  Briefs following the hearings were filed on February 26, 1999; reply briefs were submitted on March 11, 1999.  The Commission heard oral arguments and the case was submitted on March 23, 1999.
In this decision, we rely on the full record to identify the most promising options for further consideration and cost-benefit analysis in a second phase of this inquiry.  Today, we open a new docket in which we will receive the proposal settlement or the cost-benefit analysis.  This proceeding is closed.
B.	Goals
In D.98-08-030, we identified certain goals that we would pursue in assessing the existing natural gas market structures and considering a long-term strategy for regulating the industry.  We repeat those goals here to provide a context for the discussion in the remainder of the decision:
1.	To complement and enhance the benefits of electric restructuring.
2.	To eliminate inappropriate cross-subsidies.
3.	To guard against unnecessary barriers to the entry of competitors into various aspects of the natural gas market.
4.	To mitigate competitive abuses that may occur because one firm exerts inordinate control over the functioning of the marketplace.
5.	To enhance competition by providing separate rates for each major component of utility service and allowing customers to choose to have other firms substitute their services and charges where appropriate.
6.	To ensure that the rates customers pay for utility services reflect the cost of those services.
7.	To preserve the low-costs currently enjoyed by California natural gas customers.
8.	To provide adequate consumer protection.
9.	To ensure that natural gas service is safe and reliable.
III.	A Review of Specific Change Options
A.	Improving Access to Transmission and Storage Services &Transmission, Storage and Balancing Rights Trading
At issue is whether the establishment of statewide primary and secondary markets for storage and intrastate capacity rights is needed to facilitate a vibrant market for gas services.  In addition, if such an option appears promising, we must identify its crucial components.
A shipper’s or end-use customer’s ability to acquire firm capacity rights to portions of the utilities’ transmission and storage system depends on whether those rights relate to the PG&E system or the SoCalGas system.  Under the Gas Accord, shippers and customers can purchase storage or intrastate transmission rights directly from PG&E or can acquire them from other rights-purchasers through a secondary market transaction.
Under its Gas Accord, PG&E currently operates an open access intrastate transmission system, with all end users, marketers, producers and brokers able to hold path-specific firm or as-available transmission service contracts.  This includes PG&E’s Core Procurement and Utility Electric Generation (UEG) departments.  The holders of firm capacity rights control access to PG&E’s system.  These parties may sell their contractual rights to other customers in the secondary market.
PG&E maintains three gas storage fields.  Most of the capacity in those fields is dedicated to core or pipeline balancing services.  PG&E’s shareholders are at risk for the remainder of the storage costs, which the company attempts to 
recover through the sale of firm, tradable storage rights.  PG&E’s Core Department brokers any of its unused storage and transmission capacity on the secondary market.
SoCalGas does not operate under a structure similar to the Gas Accord.  It does not define components of its system as comprising intrastate transmission, as distinguished from distribution, and does not sell firm capacity rights to other parties.  SoCalGas does sell otherwise-available portions of its storage capability to end-use customers, but there is no secondary market for those rights.  If the purchaser does not use them, they revert to SoCalGas.
SoCalGas does not offer firm access to its transmission system.  No individual shipper can sign a contract that would give it firm, priority access to a receipt point on SoCalGas’ system.  By extension, there is no trading of capacity on a secondary market.  Instead, SoCalGas rations access to its system through a windowing process.  The window refers to the amount of gas SoCalGas allows to come into its system at the various interconnections with upstream pipelines.
SoCalGas owns and operates five underground storage fields.  A portion of the capacity in these fields is sold to noncore customers through tariffs and negotiated contracts.  Noncore customers also pay a portion of the storage costs in their transmission rates for balancing services.  In addition, any stranded storage costs associated with the sellable storage capacity are reallocated to customers on an equal cents per therm basis.
	Current Status of Transmission and Storage Rights
	Intrastate Transmission	Storage	Stranded Costs	
PG&E	Unlimited trading of firm access rights.	Unlimited trading of firm access rights.	Shareholders are at risk.	
SoCalGas	No shipper or customer firm access rights and no trading.	Access to a limited amount of storage, but no active secondary market.	Shareholders are partially at risk.	

Does the current structure support our goals of guarding against barriers to entry and avoiding competitive abuses?  Several parties have argued that it is more difficult for entities other than the local distribution companies to compete to provide gas service when they cannot elect to acquire firm transmission and storage rights and when there is not an effective secondary market for those rights.  We will examine intrastate transmission and storage issues in that order.
1.	Intrastate Transmission
Edison asserts that a market is inefficient when shippers cannot depend on being able to move gas from the north to the south.  This can occur when an entity has firm rights to move gas through PG&E’s pipelines but then is denied access to SoCalGas’ system through one of its pipeline windows.  For example, PG&E and Edison argue that when nominations by firm shippers on the PG&E system are reduced as a result of the window constraint at Wheeler Ridge, it has the effect of forcing these shippers to strand Canadian capacity, sell gas in the basin at lower prices, pay reservation charges on transportation they never used, and/or buy additional supplies and transportation in the future to meet supply commitments that could not be fulfilled when their nominations were reduced at Wheeler Ridge.
Edison argues that these circumstances also cause harm to Southern California end users.  First, shippers who bring Canadian gas into Southern California face substantial risk because of this uncertain window process.  The decreased confidence in the reliability of the SoCalGas system deters Canadian gas from competing in the southern California market, and thus has the effect of reducing gas-on-gas competition both in Southern and Northern California.  

Additionally, southern California shippers are harmed in the same manner as northern California shippers, described above.
PG&E reports that it has experienced significant variability in the daily capacity its shippers are allowed to use for transporting gas through Wheeler Ridge, just south of PG&E’s Kern River Station.  PG&E argues that the resulting uncertainty harms SoCalGas end users and the competitive market in several ways.  PG&E agrees with Edison that shippers bringing Canadian gas into southern California have little confidence in the reliability of the SoCalGas system and thus in their ability to serve the Southern California market.  This deters participants from using Canadian gas to compete in the Southern California market and increases the amount of Canadian gas in Northern California, again reducing gas-on-gas competition in both ends of the state.  In addition, because SoCalGas uses day-before flows to establish its windows, SoCalGas determines where large buyers with large load fluctuations will be able to buy gas.  As a result, when supplies become available in Northern California or elsewhere because of unexpected load changes, buyers in the south may not be able to get access to this potentially inexpensive gas.
SoCalGas and San Diego Gas & Electric Company (SDG&E) state that it could conceivably be beneficial to customers to create a system that would define firm intrastate transmission capacity rights to be held by customers/shippers, and that could be traded in a secondary market.  These companies recognize that such a change would allow customers to bid for capacity in a manner that reflects the value they place on it.  In addition, they acknowledge that such an approach would increase allocative efficiency and that it might also provide some economic signals related to the construction of new intrastate transmission facilities.
We agree that the creation of firm, tradable intrastate transmission rights offers the hope of achieving these objectives, as well as providing individual shippers with greater certainty as to their ability to move certain quantities of gas through the pipeline system.  This is consistent with our stated goals of enhancing competition by allowing customers to choose to have other firms substitute their services and charges, and mitigating competitive abuses that may occur because one firm exerts inordinate control over the functioning of the marketplace.  We consider the creation of a statewide system of tradable intrastate transmission rights to be worthy of closer examination in the next phase of this proceeding.
SoCalGas offers several issues for the Commission to consider in the next phase:
1.	Does the system of intrastate capacity rights created by the PG&E Gas Accord provide the model for a statewide system?  If so, has the PG&E system delivered the expected benefits?
2.	Can a definition of rights on the SoCalGas system be found that works in practice and meets customer needs?
3.	Do the possible benefits of a system of defined rights on the intrastate system outweigh the benefits of the current system in Southern California?
4.	Can a system of intrastate capacity rights be successfully harmonized with the upstream pipeline capacity rights held on the pipelines regulated by the Federal Energy Regulatory Commission (FERC)?
These are constructive questions, all of which we invite parties to address in their cost/benefit presentations.  As part of a response to the question relating to the definition of rights on the SoCalGas system, we ask parties to offer a suggested approach for identifying the functional components of the SoCalGas system and for quantifying a particular shipper/customer’s right to use one of these components.  SoCalGas should offer its suggestion for the best way to divide its system into functional components, even if the company would rather that no changes be made.
PG&E, CGC, Edison and SoCalGas devoted considerable attention to a debate over the appropriate uses for a facility referred to as the Hector Road interconnection.  SoCalGas built this facility in 1994 after receiving permission from the Commission in Resolution G-3123.  The facility connects the Mojave Pipeline to SoCalGas Line 235.  Line 235 brings gas in from the SoCalGas’ interconnection with the Transwestern Pipeline at North Needles.  The interconnection at Hector Road makes it possible to take gas from the Mojave Pipeline and deliver it to SoCalGas’ system without using the limited capacity at Wheeler Ridge.  However, when capacity on Line 235 is limited, deliveries from Hector Road could interfere with deliveries from the Transwestern Pipeline.
Shippers are not able to nominate deliveries from Mojave at the Hector Road interconnection because SoCalGas does not recognize it as a formal receipt point.  CGC asserts that, as a result, SoCalGas has complete discretion over the use of the interconnection and expresses the concern that “SoCalGas appears to be using its discretion…to assist the SoCalGas Gas Acquisition Group.”  SoCalGas originally justified this interconnection by identifying a need to improve gas flows in the eastern end of its system during winter months.  However, Edison presented evidence that suggests that the interconnection is used most from April through July.  This is the height of the core’s storage injection season.
In the agreement that was approved by Resolution G-3123, SoCalGas and Mojave agreed that “no user of SoCalGas’ system shall be disadvantaged by SoCalGas’ request for service” on the Mojave Pipeline.  SoCalGas points to this provision to assert that it cannot use the Hector Road facilities in a manner that would interfere with flows from the Transwestern Pipeline.  The company argues that it could not jeopardize the ability of Transwestern customers to fully utilize Line 235 unless the Commission modified Resolution G-3213.
SoCalGas may be making too much of the language in Resolution G‑3123.  The Commission did not order SoCalGas to refrain from creating a disadvantage for its customers through the use of the Hector Road interconnection, but merely approved an agreement for the construction of the interconnection.  In the agreement, SoCalGas and Mojave expressed the goal of avoiding any disadvantage.  It is not even clear what such language would imply.  In a resource constrained system, any time one customer gains access but another customer does not, the latter customer is at a disadvantage.  However, if the gas company is using the facilities to improve its core procurement operations while exercising its discretion to deny access to others, it is using the interconnection in a manner that may create disadvantages for others.
PG&E proposes that SoCalGas use Hector Road as a formal point of interconnection that competes for space on the system just like other interconnects.  Under this approach, PG&E and Kern River shippers would have access to more space at Wheeler Ridge and more of the low-cost Rocky Mountain and Canadian gas could flow into southern California.  As PG&E points out, gas from these sources has been the least expensive over the last four years.  In the short term, PG&E would have SoCalGas create a window for deliveries through Hector Road, just as it has at its other interconnection points.  In the long term, PG&E would have SoCalGas sell firm and as-available access rights to all of its points of interconnection.
SoCalGas opposes PG&E’s short-term proposal, arguing that market participants that have relied on the current system, in terms of their acquisition of upstream transportation rights and supply arrangements, should not have their expectations disturbed without cause.  We agree with SoCalGas’ formulation of the problem, but do not necessarily agree with its conclusion.  CGC, PG&E, and Edison assert persuasively that the failure to provide at least window-style access through Hector Road has resulted in lost opportunities for bringing relatively inexpensive gas into southern California.  In addition, some parties question whether SoCalGas’ Operations Group is making decisions about the use of the interconnection in a manner that is independent of the interests of the company’s Gas Acquisition Group.  This is a serious concern in light of Remedial Measure 12 in the Pacific Enterprises/Enova merger decision (D.98‑03‑073), which requires independent operation of the two groups.  However, the concerned parties have been unable to review any data reflecting usage of the interconnection since the adoption of Remedial Measure 12.
SoCalGas denies that it has inappropriately favored its core procurement group with access through Hector Road, but then goes on to defend its core procurement practice of bringing in gas through that facility.  Surely, SoCalGas argues, noncore purchasers want to bring gas down through Wheeler Ridge as well.  The dilemma, however, is they cannot rely on their ability to bring such gas into the system at Hector Road.
SoCalGas refers to a scenario where Mojave customers would displace Transwestern customers as a “zero sum game”.  SoCalGas would increase receipts at Hector Road only at the expense of customers who wanted to schedule receipts from Transwestern at North Needles.  The analogy to a “zero sum game” applies equally well to a constraint in the opposite direction.  When Line 235 is fully subscribed, Transwestern gas displaces Mojave gas.  The notion of a “zero sum game” has a negative connotation because it involves taking pieces of a finite pie and redistributing them.  Most people would prefer to expand the size of the pie, creating benefit for everyone.  Creating an active market for capacity rights, as we propose, is a way to enlarge the pie.  Where the transmission resources are constrained, the price offered for access will reflect high value. The resulting price signals should encourage appropriate planning for greater access.  Where transmission is constraint-free, the prices will reflect lower value and the creation of unnecessary capacity should be discouraged.
However, it is unlikely that the market will accurately reflect the value of the resources if some resources are held back.  Such would be the case if SoCalGas were to define its marketable transmission access in a way that did not include the Hector Road facilities.
PG&E points out that, at a minimum, no clear criteria appear to exist to determine when interconnection is available at Hector Road.  The record supports this assertion.  We see reason to pursue a change in protocol for receiving gas at Hector Road, even in the short term.  If there are burdens that would unfairly fall upon Transwestern customers if a window was established at Hector Road, we want to hear about it in the next phase of the proceeding.  In addition, we seek specific proposals as to how such an arrangement should be defined.
If the Commission were to move to a system of intrastate capacity allocation, such as we propose, that would allow customers to bid against each other for specific intrastate capacity, SoCalGas agrees that it might make sense to allow customers to nominate for Hector Road.  Although SoCalGas hedges its endorsement, it offers no reason why a capacity-marketing system should not include Hector Road.  As we stated above, the failure to include Hector Road in such a program might tend to skew the price signals in a manner that does not accurately reflect the available resources.  Based on what we know now,  we expect that Hector Road would be part of a marketing plan.  However, in the next phase of this inquiry, we look forward to reviewing both proposals for defining the relevant  transmission system and the analysis of the costs and benefits of exposing Hector Road and other portions of SoCalGas’ system to the forces of the marketplace.
Several parties have requested that SoCalGas publish its windowing criteria in tariffs to facilitate an understanding of the rules that the utility applies.  While it is too early to know whether SoCalGas will continue to use these windowing practices in the long term, it is appropriate for the utility to clarify its practice for the benefit of shippers as long as those practices are in place.  We will direct SoCalGas to file an advice letter containing proposed windowing tariffs within 90 days of the date of this decision.
2.	Storage
In this area, as well, it is Edison that poses fundamental issues for our consideration.  Edison describes storage ownership and operation as being very concentrated in California, with PG&E and SoCalGas being the primary holders of storage capacity and with their core procurement functions being the largest users of, and holders of, that capacity.  New entry into this market is occurring, but is difficult, as evidenced by the fact that even the Wild Goose storage field is not in operation yet.  Edison argues that new entrants also face significant challenges as they enter the market due to the conflicts of interest within the local distribution companies because they control both transmission and storage.
Edison’s witness Carpenter describes three roles for storage in the market.  First, storage is a substitute for transmission capacity on peak.  It provides reliability by assuring firm deliveries of gas during peak periods when all available transmission capacity is flowing with maximum supplies.  Second, storage performs a potential balancing function within California.  It provides supply flexibility by allowing shippers to use injection or withdrawals when they are out of balance.  Third, storage can perform a price arbitrage function that is seasonal in nature.
Edison asserts that because of the utilities’ dominant positions in the storage market, the utilities can exercise discretion in determining who should have access to storage and at what price.  However, as Wild Goose argues, it would be difficult to detect any such abuses.  Parties disagree as to whether or not there are meaningful competing alternatives.  SoCalGas argues that the services that could be provided by its storage facilities could also be achieved through the use of flowing supplies, private storage providers such as Wild Goose, and the potential buyer of SoCalGas’ Montebello storage field, which is the focus of A.98-01-015 as well as a related investigation.  However, flowing supply is not a substitute for storage if a shipper is trying to accomplish seasonal arbitrage.  Wild Goose, which is located in Northern California and has yet to go into service, is of less use to customers in the south who would incur greater transportation costs to store and retrieve gas.  Montebello has several hurdles to clear before it becomes a functioning private enterprise, and Edison argues that the sale of such a small, inefficient facility would still not create a competitive market.
New Mexico argues that the conflict is clear: “a utility will achieve a higher level of revenue if it transports gas for a storage customer and sells that customer storage capacity than if the utility merely transports gas for a customer using an independent storage provider...The incentive for a utility to manipulate its system and the prices it charges for storage and intrastate transmission is undeniable.  The linkage between storage and the utilities’ merchant function and other services is undeniable.”  This argument supports a separation of the storage function from other services and supports allowing shippers and customers to acquire firm, tradable access rights.
Under the Gas Accord, PG&E offers firm access to all of its noncore storage capacity and allows for a secondary market.  Several parties ask whether PG&E should do more to facilitate an active secondary market.  In addition, we should consider whether a storage program such as PG&E’s should be a permanent feature of the market for PG&E after the Accord lapses and for other utilities, as well.
SoCalGas proposes placing its shareholders at risk for revenues related to all of the storage capacity it currently dedicates to serving noncore customers.  In addition, SoCalGas would place its shareholders at risk for about half of the 70 billion cubic feet (BcF) of storage inventory and 327 million cubic feet per day (mmcf/d) of firm injection for which it currently receives revenues through core rates.  If the Commission were to establish daily balancing requirements, SoCalGas also proposes removing from transmission rates most of the cost of the 5 BcF of storage inventory and injection/withdrawal capacity currently dedicated to balancing services.  In exchange, SoCalGas seeks the following assurances:
1.	Core reliability would be protected by retaining in core rates approximately 35 Bcf of inventory capacity.
2.	Strict daily balancing rules would be adopted.
3.	SoCalGas would be allowed the same pricing flexibility as other storage providers.
4.	SoCalGas would be granted the flexibility to manage and dispose of its noncore storage assets without delay and Commission interference.
SoCalGas sees this proposal as a way to improve the efficiency of the industry, to give customers more choice and to provide for greater competition.  The utility does not propose to allow for a secondary market.
Edison remains critical of SoCalGas’ proposal, expressing its belief that, when taken as a whole, this approach would allow SoCalGas to exploit its dominance in the southern California storage market.  SoCalGas' proposal to implement daily balancing would likely increase the demand for storage services it alone offers in southern California, especially in light of the fact that there is no existing mechanism for shippers to trade daily imbalances.  The pricing flexibility proposed by SoCalGas would potentially allow it to raise prices in response to the increased demand brought about by strict daily balancing rules.  Furthermore, SoCalGas would potentially be able to further restrict output and raise prices if it were allowed to dispose of more of its storage assets without Commission interference, as it has proposed.  Restricting output in order to raise prices is classic monopolist behavior.
The record supports the observation that SoCalGas is the dominant provider of gas storage in southern California and is likely to remain so, even if Montebello is operated by another firm.  While flowing supply can be used to meet some of the goals of storage, it does not meet all of the goals and, by definition, is not consistently available.  In the absence of meaningful competition, it is not a promising option to grant SoCalGas unlimited ability to control prices and supply.  Some pricing flexibility may be appropriate if the company’s shareholders assume the risk for recovery of storage costs.
There is reason to believe that it would promote more efficient use of the hard-to-find gas storage resources if individual shippers and customers could bid for firm storage access rights.  In addition, the local distribution company will be motivated to pursue more complete utilization of its storage assets if its shareholder bear the risk for cost recovery.  If accompanied by an active secondary market, the bidding and trading of storage rights should lead to pricing that reflects demand.  A market-based price for storage should spur the development of more storage capacity, or other alternatives to storage, when existing capacity becomes scarce.
In addition, we anticipate that the existence of an active secondary market for storage would reduce a utility’s ability to increase its storage revenues in an unfair manner.  Shippers should be more willing to acquire storage rights when they know they will have the ability to sell unused capacity on the secondary market.  As more of the storage rights are held by market participants other than the utilities, the utilities’ ability to gain from manipulation of storage prices is reduced.  As with our proposal for transmission rights trading, this option should advance our goals of mitigating potential competitive abuses, and providing a wider array of choices to market participants.
In the next phase of this inquiry, we ask parties to consider the costs and benefits related to creating a system of tradable storage rights in Southern California that places the utility at risk for unused resources and preserving such a market in Northern California beyond the period of the Gas Accord.  As part of this discussion, we wish to consider the merits of treating the utilities’ core procurement departments like any other customer, allowing the core group to bid for and acquire needed storage in the same manner as all others.
ORA has proposed a partial divestiture of storage assets.  We discuss that proposal in the next section of this decision.
3.	Divestiture of Transmission and Storage Assets
We have discussed the conflicts of interest the gas utilities will face as the merchant gas providers for the retail core and as the owners/operators of the transmission and storage system.  Edison takes the lead in arguing that the cleanest way to remove these conflicts would be for the gas utilities to either divest themselves of assets supporting one or more of these functions, or create an independent operator for the intrastate transmission system (ISO).  ORA and Wild Goose have also expressed support for storage divestiture.  However, Edison recognizes the difficulties associated with divestiture or the establishment of an ISO.  Thus, Edison has proposed a series of interim steps, along the lines of the promising options identified in this decision, as a way to avoid these difficulties while at the same time mitigating the potential for anticompetitive abuse that exists under the current structure.
Edison suggests that the Commission may need to revisit the issue of divestiture or the establishment of an ISO if these steps are not sufficient to protect against the gas utilities’ exercise of market power.  Similarly, Enron proposes that the utilities be required to divest transmission and storage if they do not create tradable capacity rights.
At a minimum, it is appealing to consider a market in which the utility distribution companies do not have a direct interest in the viability of some storage facilities against which others are trying to compete.  Undeniably, the current arrangement provides an incentive for the distribution companies to operate their transmission systems in a manner that encourages the use of their own storage facilities instead of those owned by competitors.  The incentive is that distribution company revenues are higher when customers choose to use the company’s storage facilities.  The available tools include delay, failure to share complete information, and failure to adequately contain costs that are passed on to competing firms.  Such tools could be used in a thousand different subtle ways that would be difficult to detect and need not involve violations of existing rules.
Wild Goose says that the only viable solution is to get the distribution companies out of the storage business, by directing them to sell all of their existing storage facilities.  ORA recommends that the utilities be required to divest those storage facilities that hold gas in excess of core requirements.  However, the initial attractiveness of these options is tempered by the reality of the distribution company’s extensive need for storage to support its core procurement efforts.  Under a partial divestiture strategy, the distribution companies would retain ownership of storage needed to support the core and system balancing.  Under total divestiture, the distribution companies would need to acquire storage rights for the same purposes.  This would continue to be the case as long as the local distribution companies continue to provide the vast majority of the gas commodity service for core customers.  For reasons discussed below, we do not see the removal of the local distribution companies from the core procurement process as a promising option worthy of further study.
The storage rights related to core service are significant.  Of PG&E’s total storage capacity, 82% is devoted to core service (including core aggregators), 6% is used for balancing service, and 12% is sold to non-core users.  Even after taking core aggregators into account, PG&E asserts that it currently needs over 80% of its storage capacity to meet its responsibilities. For the foreseeable future, PG&E may need to use an equivalent amount of storage.  Whether PG&E divested itself of only what it did not need, or divested itself of everything and then purchased what it needed, it would still control the bulk of currently-available storage capacity.  If there were a vibrant secondary market for storage capacity, PG&E would remain a major player (and a major competitor) under either scenario.  After divestiture, PG&E likely would have the same incentives to protect the value of its storage assets that it has now.  These observations are applicable to SoCalGas, as well.
We are not convinced that there are clear advantages to pursuing divestiture of storage or transmission assets or the formation of a gas ISO at this time.  If the other promising options were to be adopted and did not create the improvements to the market that we would expect, we would revisit these proposals.
4.	Implications of the Open Season for Transmission Capacity on the Redwood Path
During December 1997 and January 1998, PG&E conducted an open season auction for intrastate backbone transmission capacity on Lines 400 and 401 (the “Redwood System”).  PG&E’s Utility Electric Generation (UEG) Department submitted a bid for 100 percent of the capacity available at the maximum rate and term.  Several parties have alleged that the PG&E UEG bid was unreasonable from two primary perspectives.  First, considering that the Commission previously ordered PG&E to divest nearly all of its gas-fired electric generation capacity by the end of 1998, PG&E’s UEG bid significantly in excess of its own future needs.  Second, because PG&E’s transmission department prorated the total available capacity among the top bidders and PG&E’s UEG bid the maximum amount, those requiring Redwood capacity had no choice but to inflate their own bids accordingly.  Parties contend that PG&E’s actions served to create its own market and inflated the price of Redwood capacity. 
New Mexico and Calpine point to PG&E’s initial open season of its Redwood Path capacity as a real-life example of the type of market abuse that could be avoided if the utilities were required to divest themselves of intrastate transmission.  Calpine witness Elder notes that “…this example points to the need for the Commission in developing policy solutions to remember that it’s hard to write rules that can’t later be interpreted by the utility and others differently than intended or differently than by other market participants.  We think that’s one of the reasons that divestiture in some cases is a better option than writing new rules.”
We acknowledge the concerns raised by Calpine and New Mexico.  Parties’ incentives and abilities to interpret rules to their respective advantages – especially with untested market mechanisms – present the potential for, at best, confusion in the marketplace.  More disturbing is the potential to use such different interpretations to engage in anti-competitive behavior.  However, we are not convinced that utility divestiture of their transmission assets is the most appropriate solution to the market abuse alleged by Calpine and New Mexico.
One concern we find particularly troubling is the question of new ownership of the intrastate pipelines.  Considering the expense, expertise and obligations involved with owning and operating these systems, the pool of potential buyers would likely be relatively small.  Even if an entity is financially and operationally qualified to purchase a pipeline, divestiture of the transmission facilities does not necessarily prevent against market abuse.  While the kind of market abuse alleged here may not necessarily occur after transmission divestiture, potential buyers may have other interests in the energy industry that could lead to an incentive and ability to engage in other types of anti-competitive behavior.
Furthermore, as with storage, SoCalGas and PG&E allocate significant amounts of the transmission capacity to reliably serve their respective core loads.  PG&E and SoCalGas each currently needs at least 25% of its total transmission capacity to serve its core customers.  Firm capacity needed to serve core increases significantly in the winter season for each utility.  Even if SoCalGas and PG&E  were to divest their transmission assets they would have to contract significant amounts of capacity to meet their customers’ requirements.  After divestiture they would still therefore retain control over much of the transmission system.  As a major capacity holder, divestiture likely would not change the utility incentive to manipulate the value of the transmission asset as is currently alleged by Calpine and New Mexico.
Edison adds that, at the very least, the Redwood Path open season demonstrates the need to establish clear capacity auction procedures, including yearly auctions of returned capacity.  Edison maintains that there should be no caps on auction prices, but that premiums in excess of book value should be returned to ratepayers.
Regardless of the outcome of the Commission’s investigation into Enron’s emergency motion on the initial Redwood Path open season, we are persuaded that it makes sense to establish clear procedures for allocating capacity.  While we are not addressing here many of the specific concerns raised by parties about PG&E’s open season, the scope of concerns raised indicates to us that the processes used for future open seasons need some attention in order to ensure that they result in fair outcomes.  We have already indicated that creating firm, tradable capacity rights on the intrastate natural gas transmission systems is an option worthy of further evaluation.  We would consider clear processes to allocate that firm and secondary capacity to be an important component in that effort.
A capacity allocation process may take the form of an auction, or may be structured differently.  In the hearings, several parties identified the issues to consider in improving upon the procedures used in PG&E’s Redwood capacity auction.  Such issues include whether and how to restrict any one party’s participation in capacity auctions (especially utility affiliates), use of a price cap on initial capacity offerings, and ensuring that the bidding procedures used are clear to all participants.  In their analysis of the costs and benefits related to tradable transmission rights, we encourage parties to discuss appropriate capacity allocation mechanisms.
B.	Improving Balancing Practices
The amount of gas delivered to the pipeline system does not precisely match the amount of gas taken off the system at any given time.  Thus, if a utility wants to maintain a certain operating pressure without curtailing users or placing more demands on shippers, it must be prepared to introduce more gas to the system when supplies are low and draw gas off the system when the supplies are too high.  This process is referred to as “balancing service.”  This service offers shippers the benefit of maintaining somewhat of an imbalance between their respective input and output.
Each utility defines a tolerance band within which a shipper’s deliveries can differ from its customers’ usage.  SoCalGas requires shippers to deliver gas to the system that is within 10% of usage by the end of the month.  PG&E offers monthly tolerances in some situations as high as 25% and in other situations as low as 5%.  When the system becomes severely out of balance, the utility can take steps to require each shipper to either balance its supplies or pay a penalty.  PG&E refers to these events as Operational Flow Orders when supply exceeds or falls short of a certain tolerance band of forecast demand.  It may declare an Emergency Flow Order when such conditions threaten deliveries to end-use customers.  SoCalGas refers to these circumstances as either over-nomination or under-nomination events.
Both companies traditionally relied on core procurement supplies to balance their systems.  In the Gas Accord, PG&E recognized that this practice resulted in a subsidy for noncore customers and agreed that Core Procurement would be responsible to balance its own supplies, but not the supplies of others.  SoCalGas does not maintain a rigid separation between its core supplies and the balancing function.
1.	PG&E’s OFOs
PG&E may declare an Operational Flow Order (OFO) when it expects the pipeline inventory to exceed desired inventory by 200 mmcf/d or fall below desired inventory by 105 mmcf/d.  During an OFO, customers must balance their supplies and usage on a daily basis.  Once an OFO is declared on the system, the customer faces paying increasingly significant penalties depending on the level of imbalance.  PG&E gives at least twelve hours notice of an OFO to customers.  In an Emergency Flow Order situation, PG&E may enforce a zero tolerance band and divert gas supply from noncore to core end-use customers.
Since it implemented the Gas Accord last year, PG&E has called OFOs approximately five times a month.  Shippers are concerned not only with the frequency of OFOs but with the difficulty of predicting when they will be called.  They are concerned because they must often take expensive steps to correct imbalances such as buying gas on short notice, drawing uneconomic supplies from storage, buying short-term storage access or selling gas at a loss.  They want more and better information about the status of PG&E’s system to allow them to more intelligently predict when system constraints are likely to lead to an OFO or EFO.
It is difficult to determine whether the number of OFOs called by PG&E thus far is excessive.  We lack a reasonable yardstick with which to measure appropriate balancing practice in the new world of the Gas Accord.  The large number of OFOs may reflect the need for shippers to adapt to new balancing expectations and for PG&E to learn how to adjust its balancing practices.  There has been too little experience under the Gas Accord for us to conclude that further structural changes are needed in response to the frequency of OFOs.  However, it is clear that shippers need to be better-equipped to anticipate and respond to OFOs.  In another portion of this decision, we will address the specific information needs that shippers have identified and discuss the merits of their information requests.
Some parties suggest that the frequency of OFOs is an indication that PG&E is not devoting sufficient resources to the balancing function. Whether or not the frequency of OFOs should be characterized as excessive, it is logical to assume that if PG&E had more storage capacity set aside to support its balancing efforts, it would have greater ability to smooth out fluctuations in system balance without calling OFOs or undertaking curtailments.  The critical question is whether the benefits of adding to the assets used to provide balancing service outweigh the costs.  In the next phase, we ask PG&E to identify the incremental cost of expanding balancing services and ask all interested parties to address the economics of this step.
A third concern is that PG&E might be motivated to call OFOs because it stands to benefit if shippers feel compelled to use some of its ancillary gas services.  As operators of large, integrated gas systems, both PG&E and SoCalGas offer what are often referred to as hub services.  These predominantly involve parking services, where the utility finds a way to temporarily hold an extra gas supply somewhere in the system; and lending services, where the utility sells some of its system gas to a customer for short-term use.  These large companies can provide such services because they control vertically-integrated resources and are in a good position to know where the short-term parking or lending opportunities exist on the system on any given day.  PG&E’s shareholders benefit from any hub service revenues.  SoCalGas uses core assets to provide hub services and shares any resulting revenues with its ratepayers.
The concern is that PG&E might be motivated to call OFOs in order to attract more business for its hub services group.  It is undeniable that PG&E’s ability to retain hub services revenues creates an incentive to increase opportunities to sell those services.  It is also clear that such an opportunity makes PG&E to some degree less than disinterested in deciding whether or not to call an OFO.
What is less clear is how powerful this incentive is in the context of all the economic signals to which PG&E must respond.  We will address other aspects of hub services below.  What is important for our consideration in the context of balancing practices is that hub service revenues have thus far been minimal and that the record does not show a pattern of increased demand for hub services during OFOs.  According to PG&E, approximately 75 percent of its hub service transactions extend more than one month and very few are “intra-day” deals, and only four hub service transactions were recorded during the first six months of the Gas Accord.  The record before us does not demonstrate that PG&E called OFOs in order to attract hub services customers.
In the hearings, much attention was paid to the matter of which customer group is primarily responsible for the circumstances leading to OFOs.  This is an interesting question because PG&E manages both the transmission system and the core procurement process.  PG&E’s rate scheme includes a Core Procurement Incentive Mechanism through which shareholders are rewarded when core gas costs are reduced.  Some parties suggest that PG&E would be encouraged to use the system balancing inventory to optimize its ability to supply low-cost gas to core customers.  The Department of General Services (DGS) points specifically to PG&E’s practices in December 1998 when PG&E was forced to curtail 76 of its noncore customers in order to ensure firm service to its core customers.  DGS suggests that removal of the utility procurement function might eliminate any conflict of interest the utility may have in using the balancing function to minimize gas costs for its own procurement customers.
In such circumstances, there certainly is a possibility that PG&E would seek to take advantage of its dual status as core provider and manager of its pipeline system.  However, the evidence before us does not support a conclusion that PG&E has acted in an inappropriate manner.  The core customers’ high-priority status ensures that they will receive service even if the core procurement group has under-forecast or has elected, because of high cost or other factors, not to acquire sufficient gas.  In the event of curtailment, these failures could inflict costs on noncore customers.
These would be serious and unacceptable circumstance, if they were to occur.  Yet it would not be prudent to respond to this concern by taking draconian steps such as proposing that the utility divest its procurement function.  We are persuaded by many parties that the first response should be to improve the real-time, detailed information about PG&E’s balancing practices that is made available to market participants.  This will provide greater opportunity for continuous oversight of PG&E’s practices and should serve to discourage any inappropriate exercise of discretion.
2.	SoCalGas’ Overnomination Events
From April through October each year, gas usage is comparatively low and SoCalGas generally does not have to place tight balancing constraints on its customers.  When system tolerances are exceeded, SoCalGas can declare an over-nomination event.  Short of that, the only requirement is that at the end of the month, each customer’s deliveries, including any storage injections and withdrawals it has purchased, must be within 10% of the amount that the customer used.
During the remaining months, SoCalGas requires its customers to deliver at least 50% of their consumption over a 5 day period.  If total storage inventory falls below a certain level, the utility requires customers to deliver at least 70% of their expected usage on a daily basis.  If storage inventories are even further reduced, customers are obligated to deliver at least 90% of their expected usage on a daily basis.  The utility’s core group is subject to a separate, non-discretionary requirement that it deliver a certain minimum amount of gas to flowing supplies every day during this period.  SoCalGas can penalize customers who fail to meet their balancing requirements.  The utility’s core group is not subject to such penalties.
SoCalGas, which does not operate under an agreement similar to the Gas Accord, has not been declaring over- or under-nomination events as often as PG&E has been calling OFOs.  One reason for this difference may be that SoCalGas uses a window process that controls the delivery of gas at certain interconnection points while PG&E places greater reliance on individual shippers meeting their obligations to balance usage and delivery.  In effect, SoCalGas can help keep its system in balance by controlling the flows through its interconnection points on a daily basis.  Another distinction is that SoCalGas uses its core resources to balance its system, while PG&E is expressly precluded from doing so under its Gas Accord.
Several parties have focussed on the issue of whether one customer class is predominantly responsible for the over-nomination events that do occur.  As long as SoCalGas depends on core resources to balance its system, it is hard for us to identify the class most responsible for over-nominations.  Available statistics do not provide a clear answer.  SoCalGas reports that its Gas Acquisition Department “substantially contributed” to four out of 23 over-nomination events in 1997 and 1998;  the non-electric generator noncore group substantially contributed to 12 events, and electric generators contributed to 13 of the 23 events.
In addition, it is possible that SoCalGas would be motivated to avoid declaring such an event on days when its Gas Acquisition Department is out of balance.  On the other hand, since the system uses core resources for balancing, one could argue that it is appropriate for the core department not to be charged penalties even when it contributes to over-nominations.
The challenge is that as long as SoCalGas’ core services are intertwined with its management of its pipeline system, it is unlikely that we can ensure that the process is free of cross-subsidies or that SoCalGas is not making decisions that enhance its shareholder interests at the expense of other customers.  Core customers might be subsidizing noncore users in times when core resources are preventing the system from reaching an intolerable imbalance.  Noncore customers might be subsidizing the core if the core group is generating imbalances in its effort to optimize its cost of gas.
A related question is whether either the core group or noncore customers use more balancing resources than they pay for.  Edison argues that while the core group pays five percent of the system balancing cost, it may use a greater percentage of the balancing resources.  SoCalGas argues that on many days, the company relies on core storage assets to keep the system in balance.  These are not assets that are specifically reserved for balancing service.  Thus, it is likely that noncore customers get more balancing support than they pay for.
This not the first time that the Commission has considered questions about the use of core assets to balance the SoCalGas system.  As part of its merger with SDG&E, SoCalGas was obligated to comply with various remedial measures.  Under Measure 17, SoCalGas agreed to propose, in this proceeding, “a set of provisions designed to eliminate the need for SoCalGas Acquisition to provide system balancing.”  Measure 17 envisions that the system reliability and balancing functions would be separated from Gas Acquisition and then requires that most future communications between Gas Operation and Gas Acquisition be posted on a web site.  SoCalGas responded to these obligations by proposing to tighten its balancing requirements through the use of daily balancing.
As we will discuss further below, we are not prepared to propose the institution of mandatory daily balancing.  In addition, the SoCalGas proposal does not constitute a specific plan for removing core assets from the balancing function.  All that one can hope to do by tightening the balancing requirements on individual shippers is reduce the likelihood of a system imbalance.  However, the pipeline needs to stand ready to balance, regardless of the obligations born by individual customers.  SoCalGas has not offered a plan for ensuring that it will not need to turn to core assets to achieve this balance.
Just as it is logical for PG&E to examine strategies for devoting more assets to the balancing function in response to the high incidence of OFOs, SoCalGas must examine structural means for providing balancing services without drawing on core assets.  We view this option as a critical element in achieving our goals of eliminating inappropriate cross-subsidies and mitigating potential competitive abuses.  We will direct SoCalGas to prepare such a proposal as part of its cost/benefit analysis for the next phase of our inquiry.
3.	Daily Balancing and the Unbundling of Balancing Services
A system of daily balancing is one in which each customer is responsible for matching its deliveries with its demand, plus or minus a tolerance band, on a daily basis.  SoCalGas, in effect, requires daily balancing during winter and a month on either side.  SoCalGas proposes that we adopt a year-around daily balancing requirement.  PG&E and most other parties oppose the imposition of such a requirement at this time.
Edison states that the Commission should not adopt daily balancing for SoCalGas without first testing the effect of new, stricter monthly balancing rules adopted in the last SoCalGas Biennial Cost Allocation Proceeding (BCAP).  DGS proposes that the core group be required to be in balance every day.  California Generation Coalition (CGC) opposes daily balancing on the grounds that it would work to the advantage of those customers who currently have intrastate transmission capacity.  CGC expresses the concern that those customers who did not bid to acquire firm capacity in the Gas Accord auction, would be subject to price extortion at the hands of the Southwestern suppliers. CGC argues that the value of Redwood capacity would change under a daily balancing framework and that many parties would be placed at a disadvantage since daily balancing was not a factor when the Redwood auction occurred.  PG&E opposes daily balancing at this time because it involves resolution of a host of new issues such as the need for new systems, more real-time information tools, evaluation of tradeoffs involved, and revisions to the Gas Accord.  Enron recommends that the costs and rates for balancing services be separated from those related to other aspects of transmission service, making the purchase of those services optional for transmission customers.
It would be premature to pursue a daily balancing requirement at this time.  We need to see if the pattern of OFOs changes as the Gas Accord reforms mature.  We want to work with SoCalGas to develop a meaningful separation between its core group and its balancing services.  Most importantly, it is most critical to improve the exchange of information that affects shippers’ balancing strategies.
Short of requiring daily balancing for all customers, however, the provision of a daily balancing option may be necessary in order to implement other reforms such as the electronic trading of imbalances as well as cost and rate separation for balancing services.  We discuss this further in the next section.
The creation of separate, avoidable rates for balancing services might facilitate the entry of competitors who would provide balancing services along with procurement, storage, as well as intrastate and interstate transmission.  Cost and rate separation for balancing services might also facilitate the provision of a variety of balancing services on the part of the utility as well as competitors.  Examples of such services would include daily balancing with varying tolerance bands and penalties as well as more generous monthly balancing tariffs, with costlier charges.
We envision a scenario in which customers could elect to commit to daily balancing or to adhere to reduced imbalance tolerances, in exchange for avoiding some or all of the balancing charges otherwise imposed by the local distribution company.  A customer with daily balancing service would be likely to use some utility storage for a modest tolerance band, while customers with monthly balancing service would use more of the utility’s storage balancing allocation, and therefore pay higher rates.  The utility would still balance its system the way it currently does, with the daily balancing customers being more or less in balance and the monthly balancing customers subject to penalties similar to those in existence today.  The utility would still allocate a fixed amount of its storage to balancing, the cost of which would be shown on the bills of those customers who avail themselves of the service.
We see this as a promising option, consistent with our goal of providing separate rates for each major component of utility service and allowing customers to choose to have other firms substitute their services and charges where appropriate.  It should help ensure that the rates customers pay for utility service reflect the cost of those services, and enhance the overall efficiency of balancing practices.  We plan to consider the costs and benefits of the daily balancing option in the next phase of this inquiry.
4.	Targeted OFOs
Generally, during an OFO or over-nomination event, all shippers are required to come into balance to avoid penalties.  Calpine argues that only customers who are significant contributors to an imbalance should pay penalties and therefore recommends that PG&E should impose targeted, customer-specific OFOs.  PG&E argues that targeted OFOs do not work.  If PG&E asks one customer to correct an imbalance caused by too much gas on the system, that customer will simply pass on his inventory to another customer without improving the overall system balance.  Pipeline imbalances can build over several days, caused by one or more customers, but those particular customers may be in balance on the day of the OFO.  PG&E argues that it has no way of imposing OFOs retroactively.
We are not persuaded by PG&E’s arguments.  While it is possible that some customers might respond to a targeted request by shifting excess gas to other customers, targeted OFOs could also improve the system balance.  In fact, PG&E stated that it has already implemented targeted OFOs and that they are having the effect of reducing system imbalances on the PG&E system.
While a targeted OFO alone may not be enough to keep the system in balance, it may be a constructive starting point in some situations.  Therefore, we plan to explore targeted OFOs along with other similar reforms in the cost-benefit phase.
5.	Imbalance Rights Trading
Edison, Calpine, CGC, Pan Canadian, Enron and Wild Goose advocate the creation of a system where shippers could trade imbalance rights among shippers via a real time electronic trading bulletin board, and confirm such trades with the utilities on the same electronic bulletin boards.  This process would be maintained by the utilities.  The FERC has already recognized that the trading of imbalance rights is the preferred method for offsetting dispersions in the market caused by daily balancing or OFOs.
We find that the concept of imbalance rights trading holds sufficient promise to merit further study for several reasons.  First, as Edison points out, all customers are charged for balancing on the local systems whether they use their balancing rights or not.  Therefore, since a balancing tolerance is paid for by shippers as a component of their intrastate transmission rates, the plus- or minus- tolerance that shippers are allowed to have on a daily or monthly basis is a right that they are entitled to and that they should be allowed to trade or sell.
Second, the trading of imbalance rights would give shippers the ability to deal with daily balancing rules, where they apply, during a given day’s nomination cycles.  Currently, there is a lack of alternatives and competitive choices for shippers (in particular, gas-fired electric generators) to deal with same-day imbalance situations.  Gas-fired electric generators have little control over the amount of gas they use on the local distribution systems because they must schedule their gas purchases with the local distribution company before final schedules are confirmed with the PX/ISO.
Edison argues persuasively that the implementation of a real-time trading system of imbalance rights has several advantages:
1.	There would be real alternatives to current Local Distribution Company services (typically hub or storage) for shippers, especially for those in a same-day imbalance situation.
2.	There would be competitive choices in price discovery.
3.	A better-informed and more efficient marketplace would be fostered that would minimize uneconomic costs.  Parties may be more readily willing to trade imbalance rights that they are not using than selling the gas commodity.  At the minimum, there would be another product to help shippers stay in balance.
4.	Such a program would minimize any discretion that the local distribution companies currently possess with respect to approving transactions among third parties.  The execution of an electronic trade should be all the notification that the distribution companies require to effectuate the trade.
Edison argues that the distribution utilities should maintain the electronic trading system because they own the meters and the electronic data is already being transmitted to them.  In addition, according to Edison, the distribution company would have to recognize the trade.  It would therefore be efficient and facilitate matters if executed trades were electronically submitted to the distribution company so that it could recognize and effectuate the trade. Even if this system were developed by a third party, the distribution utility would have to endorse the system.  For example, the utilities may have to change some of their tariffs and change their systems to accommodate the trading of rights.
PG&E initially offered three reasons that the Commission should reject this proposal.  First, PG&E argues that shippers are already free to trade gas throughout the day.  However, as Edison’s witness Cushnie testified, the intraday market is thinly traded.  Furthermore, trading imbalance rights is different than trading the commodity.  Cushnie testified that parties may be much more willing to trade imbalance rights that they are not using rather than selling molecules.
Second, PG&E argues that imbalance trading does not change the physical flow on the system, and therefore does not alleviate the OFO condition of having too much or too little gas in the pipeline.  It is not clear that an imbalance rights trading program would not have a physical affect on the system.  PG&E’s witness testified that parties often react to an OFO in a manner that results in an over-correction, i.e., the system changes from over-subscribed to under-subscribed, or vice versa.  Logically, it would appear that such swings could be temporized if some shippers could balance their positions through the trading of rights.  Indeed, Cushnie testified that daily imbalance trading could reduce the swings PG&E experiences on its system after calling OFOs.  Cushnie also points out that, even if flows do not change, daily imbalance trading would reduce penalties incurred by shippers if the system is not exactly balanced, and society would avoid unnecessary costs.  Calpine witness Barnes testified that a daily imbalance trading mechanism would allow shippers who are within the established tolerance levels to trade their balancing rights and lower overall costs.
Third, PG&E argues that a daily imbalance trading mechanism is likely to entail substantial costs.  Edison responds that the costs of a daily imbalance trading mechanism cannot be specified until the details of the mechanism are worked out.  PG&E claims that the costs would be high since PG&E has limited information on what any customer is doing on a minute-by-minute, or hour-by-hour basis.  However, Cushnie testified that imbalance trading could be done the day after flow day.
We find the concept of imbalance trading to hold sufficient promise to merit further inquiry.  In the next phase, we encourage parties to consider whether a mechanism could be developed to produce the hoped-for benefits of improving the economic efficiency of the gas system and providing an effective additional tool for shippers to use in their efforts to manage supplies.  We want to know what an effective mechanism would look like and how its costs compare to its benefits.
C.	Appropriate Conditions for the Offering of Hub Services
In the section above on balancing services, we briefly described the hub services offered by SoCalGas and PG&E.  SoCalGas makes use of its core assets to supplement its hub service offerings.  It shares any resulting revenues with ratepayers through its Gas Cost Incentive Mechanism (GCIM), the mechanism that rewards shareholders for purchasing low cost core gas.  PG&E does not use core assets to provide hub services.  Its shareholders are at risk for any program costs and reap the full benefit of any resulting revenues.  Both provide hub services through market-based rates, subject to a price cap and floor.
Shippers use hub services primarily for two reasons: to support efforts at gas price arbitrage, and to compensate for short-term imbalances.
1.	Lack of Competition and Resulting Price Discrimination for Hub Services
Edison argues that a competitive hub services market does not yet exist in California.  To support its position, Edison offers evidence that both PG&E and SoCalGas exercise considerable discretion in the offering and pricing terms of hub services.  At various times, SoCalGas and PG&E have entered into agreements to provide similar services on the same day but at widely disparate prices, suggesting that the local distribution companies have the luxury of offering discriminatory prices for hub services.  Edison also reports that on some occasions, it asked SoCalGas for short term transmission services, only to be referred to the hub services group.  When it approached the hub, however, SoCalGas offered the services at prohibitively expensive rates.
The challenge in assessing this evidence is the suggestion, offered by both SoCalGas and PG&E, is that no two hub transactions are directly comparable.  PG&E states that prices will vary because almost every transaction is unique and market conditions can change minute by minute.  SoCalGas explains that another “missing ingredient” is the “individual customer expectation.”  SoCalGas admits that it charges different prices for hub services that are virtually the same.  During the hearings, SoCalGas’ witness explained that “many, many times, the hub will negotiate a service and a fee with one customer and immediately thereafter another customer will call and have different expectations and we’ll negotiate a different fee.  It happens every day.”
Edison claims that it is very difficult to track these hub transactions because SoCalGas might record same-day transactions in different quarterly reports.  Due to the lack of data, Edison states, it is difficult to determine if the discrepancy in prices is due to market conditions or due to a discriminatory use of pricing discretion.
SoCalGas argues that the disparity in pricing can be explained by factors not reported in the quarterly hub reports.  This could include, (a) whether the new transaction is actually an amendment to a prior one, (b) the negotiation date, (c) the start and end date, (d) the repayment location and terms, (e) whether or not the transaction involves a utility affiliate, (f) whether it is a combined transaction such as a park and wheel; and (g) the delivery and re-delivery points.
The utilities argue that what seems like price discrimination is actually a mechanism for prioritizing hub service transactions so that the customer who pays a higher price gets higher transmission priority relative to one who pays a lower price.  PG&E explains that the priority determines whether or not the shipper’s gas flow on a particular day.  If parking and lending transactions signed by PG&E exceed the transmission capacity available for the day, the lower priced transactions will be curtailed.
We lack sufficient information to determine whether the utilities have exercised price discrimination.  However, the evidence suggests that the utilities have extracted very different fees from different customers for what appear to be very similar services.  We are struck by SoCalGas’ suggestion that such price disparity may simply reflect the “different expectations” of different customers.  We are concerned that “different expectations” could be a euphemism, covering such challenges as being subject to inaccurate information, lacking access to sufficient and timely accurate information, or lacking confidence that the hub services provider will negotiate in good faith.  It is incompatible with our goal of promoting an efficient and active natural gas market to allow for these types of expectations to control market transactions.
As with balancing services, information seems to be the key to effective participation in the hub services market.  We discuss the issue of information regarding hub services transactions below.  In addition, the development of a strong secondary market for transmission and storage is critical to the development of effective competition for hub services.
As new storage providers such as Wild Goose go into operation, they should be able to provide an alternative to the utility’s hub services on the PG&E system, since under the Accord, any party can also hold rights to firm capacity on the PG&E system.  On the SoCalGas system, there is less potential for competition until the company establishes a system of firm, tradable rights to storage and transmission capacity.  Currently, SoCalGas has no effective competition and can therefore offer the services at its own discretion.  If hub services are to be truly useful, they should be available to customers in times of imbalances as well as for short-term hedging of gas purchases.
2.	Hub Services In the SoCalGas GCIM
Revenues associated with SoCalGas’ hub services reduce the actual gas costs recorded by the Company in its GCIM.  We approved this procedure in D.97-04-082 in a SoCalGas BCAP and in D.97-06-061 in a GCIM proceeding.  In our BCAP decision, we found that “it is core flowing supplies that are essential to providing Hub services, and, therefore, we find that Hub net revenues should be used to lower the cost of gas to the core, not shared among all customer classes.”   Under this procedure, shareholders benefit because SoCalGas’ actual gas costs are reduced so there is greater likelihood of a shareholder reward, and core customers benefit because gas costs are reduced.
A number of parties have recommended that hub service revenues be removed from the GCIM calculation.  These parties perceive a conflict of interest whereby shareholders could benefit if the Company steers or forces customers to use hub services.  Edison disagrees that core assets are being used to provide hub services.
While ORA supports SoCalGas’ inclusion of hub revenues in the GCIM, it also recommended “a clear separation between utility core procurement and the utility transmission and distribution operations.”  SoCalGas states that it does not receive much revenue from hub services, and asserts that core customers should benefit from hub services because hub services uses assets which are paid for by core customers.  However, we would prefer to eliminate the possibility of a conflict of interest, treat core customers like any other customer, and separate hub services, when possible, from the procurement function.  PG&E does not include hub services revenues in its Core Procurement Incentive Mechanism (CPIM) calculations, and treats its core customers like other customers, so we presume this does not represent a significant difficulty.
We should examine this issue in the cost/benefit phase of this proceeding.  Since we are also recommending that SoCalGas unbundle its intrastate transmission service, the ability of SoCalGas to balance its system and that is achieved could be affected by the separation of hub services from procurement for SoCalGas.  It could also result in shifting of costs.  One possibility is that hub services revenues would be removed from the GCIM calculation, and returned to ratepayer classes in proportion to the percentages which they pay for the assets needed to perform the service.  These issues are ripe for further exploration.
D.	Changing Core Procurement Services
Here, we will address the issue of whether local distribution companies should be removed from core gas procurement, whether modifications to current core gas procurement service should be made to enhance competition and customer choice, and whether other modifications to the terms for other core services should be made.  Our recommendations are:
1.	Retain the local distribution company as the default core gas procurement provider at this time;
2.	If core marketers are able to obtain market share exceeding 30% of core customers in any particular service territory, we should re-examine the issue of local distribution company default provider status for that service territory;
3.	Eliminate the core aggregation thresholds after the adoption of appropriate consumer protection measures;
4.	Unbundle SoCalGas’ interstate capacity costs, as soon as possible;
5.	Eliminate the 10% core aggregation cap;
6.	Explore the unbundling of storage costs for core customers in the cost-benefit phase;
7.	Eliminate core subscription by April 1, 2001, and require that any noncore customer who prefers to continue procurement from local distribution companies after that date to take and pay for core service;
8.	To the extent reasonable as determined in the cost-benefit phase, separate the costs and rates for core utility services including core procurement, transmission, storage, distribution, and balancing, and treat the local distribution company core procurement departments as a single customer for operational purposes, which is subject to the same terms and conditions of service as other customers.  This includes exploring whether SoCalGas’ hub services revenues should be taken out of the GCIM calculation, and if so, how such revenues should be treated.
9.	The Utilicorp proposal to replace the core and noncore customer classes with firm and non-firm classes is premature, but could be explored at a later time;
10.	Explore in the cost-benefit phase whether it makes sense to pursue targeted OFOs, but not specifically directed at core customers, and the extent to which core load forecast data should be provided.
1.	Core Procurement
The local distribution companies in California provide the bulk of core procurement service.  About 99% of residential load is served by the local distribution companies and about 82 to 85% of core commercial load is served by the local distribution companies.  Core aggregation has been allowed in California since 1991.  Many smaller noncore customers still prefer core subscription service, but non-utility marketers provide procurement for the bulk of the total volume of noncore load.  For example, other marketers serve 98% of the noncore load in the SoCalGas territory.
In its “Strategies for Natural Gas Reform,” the Division of Strategic Planning made a preliminary recommendation to remove the local distribution companies from the core procurement function.  This was based on the observation that marketers had failed to obtain much of a share of the core procurement market, even though core aggregation had been allowed since 1991, the perception that removal of the local distribution companies would lead to a greater degree of customer choice and competition for core procurement customers, and concern about the utility incentive and ability to leverage the core procurement to the advantage of its other gas services.  Enron and El Paso initially endorsed this recommendation, arguing that the involvement was stifling competition.  The utilities and several other parties oppose this recommendation, arguing that the local distribution companies perform a valuable service.  A few parties, such as CIG/CMA, DGS and Calpine recommend that this step be considered if certain operational problems, particularly those related to PG&E’s OFOs, cannot be reduced.
After reviewing the Market Conditions reports and hearing testimony in this proceeding, our recommendation is to retain local distribution company core procurement services at this time, while modifying certain aspects of the local distribution companies’ core procurement services.  The local distribution companies perform a valuable service for core customers, and we have seen no compelling reason to remove the local distribution companies from that service.
We find this recommendation to be consistent with many of the goals articulated at the outset of this proceeding.  Most importantly, we believe this option will help preserve the low costs currently enjoyed by California natural gas customers, provide adequate consumer protection, and ensure the reliability of natural gas service.
There is no evidence that core customers are being harmed by local distribution company core procurement service.  On the contrary, there is evidence that core customers benefit from local distribution company core procurement.  The local distribution companies have an incentive to provide core customers with gas supplies at the lowest cost reasonably possible, consistent with assuring reliability of that supply.  The gas procurement performance-based ratemaking mechanisms (PBRs) we have adopted appear to be one of our regulatory successes as far as core customers are concerned.  Both ORA and TURN, the only active parties representing core customers’ interests, argue in favor of continued local distribution company core procurement and the gas PBRs we have adopted.
We began adopting gas PBRs six years ago, and have been conducting annual reviews of the gas procurement performance of the local distribution companies.  The record in those reviews shows that the local distribution companies have procured gas supply at or, in most cases, below the gas PBR benchmark prices, which are intended to reflect the market price of gas.  Virtually no other party beyond the utility and ORA typically participates in those reviews, and we have received no complaints that the gas PBRs are harming core customers.  Indeed, some parties in this proceeding argued that the gas PBR incentives work too well.
While some modifications of local distribution company core procurement may therefore be necessary, it still illustrates the point that the local distribution companies have a clear incentive to keep core gas costs low.  We have also observed that gas PBRs have significantly reduced regulatory resources devoted to gas procurement reasonableness reviews.
Beyond noting that no significant benefit would occur with removal, several parties also discuss how the removal of local distribution companies from core procurement could result in higher costs for core customers.  ORA discussed the additional costs which might be incurred in the removal of local distribution companies from core procurement.
ORA notes that the local distribution companies procure supplies under something “similar to a price cap,” and that if the local distribution companies were removed from core procurement, the price cap would essentially be lifted.  Edison noted that local distribution companies have no markup, other than core brokerage fee, on core procurement costs, so “…if the Commission’s aim is to have more competition, then it would be doing so probably at the risk of raising consumers’ cost.”  There is also the possibility that some stranded costs would be passed on to customers.  TURN argues that local distribution company divestment of the core procurement function would require consideration of issues related to service reliability.
There is no evidence that the local distribution companies have market power with regard to the actual procurement of gas supply.  That is, there is no evidence that any local distribution company was able to manipulate market basin supply prices to its advantage.  In addition, SoCalGas states that at least 30 other gas marketers have greater trading volume (nationally) than SoCalGas’ core procurement volume, and nearly all of these marketers are active in California.  The trading volumes for the top ten of these marketers, including Enron at the top of the list, range from 5 to 11 times SoCalGas’ core volumes.
Competition for core procurement already exists, the gas commodity marketplace is highly competitive, and no party has demonstrated that removal of the local distribution companies from core procurement would necessarily result in any greater degree of competition than currently exists, and is allowed by the Commission.  A number of parties express the belief that core customers want at least the option of relying on local distribution company core procurement.  No party stated that core customers were demanding the removal of local distribution companies from core procurement.
Some parties assert that any benefits of procurement competition have already occurred.  We discuss below the reasons why core aggregators have not obtained a higher market share of the core procurement market.  Enron itself recognizes the possibility that a few dominant firms might simply replace the local distribution company as the holder of intrastate capacity when it suggests that market participants in an auction for intrastate capacity should be limited to a 20% share of the core procurement market.  From where we stand today, we do not see why a firm which is able to offer low gas prices should be limited to a 20% market share.  This would also limit the incentive to attract additional customers once a firm had a 20% market share.
In suggesting that local distribution companies be removed from core procurement as a “near- to medium-term” goal, Enron recommends an “auction” for the default provider service, and was the only party to make such a proposal.  Enron does not base its recommendation on any significant evidence, and does not provide any evidence that its proposal would benefit core customers.  As noted above, other parties asserted that Enron’s proposal for local distribution company divestment of the core procurement function might result in higher costs for core customers, and could impact service reliability.
We find that there is no reason to conduct an auction.  In effect, an auction is already conducted through the competitive market – most customers are able to compare prices offered by local distribution companies and marketers and are able to buy gas from whomever they want (except that currently our core aggregation rules require a threshold volume of customers).  In addition, there are numerous issues we would need to examine in allowing another firm or firms to be responsible for default service.
There was little support shown in the market conditions reports, opening or reply briefs, or hearings for removal of local distribution companies from core procurement.  In fact,  the only core representatives, TURN and ORA, opposed removal.  The local distribution companies, CCUE, and Edison also opposed removal.  Enron was the only party to actually recommend a mechanism which could potentially result in removal, as a near- to medium term goal.
A small number of other parties (CIG/CMA, Calpine, and DGS suggested that removal of the local distribution companies from core procurement should be considered.  However, although these parties seemed to make their recommendation as a secondary proposal, while their primary goals were to eliminate significant  local distribution company conflicts of interest or performance problems in other areas of local distribution company services, especially related to PG&E OFOs.   These parties asserted that too many OFOs were occurring, there was a perceived conflict of interest related to the PG&E CPIM or the SoCalGas GCIM, and that if OFOs weren’t reduced, then removal of the local distribution company from the procurement function might be an appropriate remedy due to the perceived conflict of interest.
We discuss in other sections of this decision our recommendations on how to deal with PG&E’s OFOs and other aspects of operational problems related to a perceived conflict of interest with local distribution company core procurement.  At this point, we do not believe the alleged problems warrant consideration of local distribution company removal from core procurement.
No party has raised concerns regarding the core procurement services of the smaller local distribution companies, Southwest Gas and WP Natural Gas.  WP Natural Gas argues that removal of local distribution company core procurement wouldn’t make sense in its service territory and for the smaller utilities in general, and its customers have not voiced concerns about this service.  Southwest Gas also asserts that it offers the lowest gas rates in the state, an assertion that was not countered in this proceeding.  Also, virtually no party raised concerns specifically directed at SDG&E’s core procurement services.
There are various likely reasons for this, including SDG&E’s gas PBR, SDG&E’s relatively small holding of interstate pipeline capacity (which is unbundled in any case), SDG&E’s relatively small size compared to SoCalGas and PG&E, SDG&E’s lack of hub services or storage assets, and SDG&E’s lack of a significant intrastate transmission service.  Indeed, SDG&E and the other small local distribution companies continue to purchase gas for much of their noncore load due to their particular situations.  Almost all of the concerns raised in this proceeding about perceived conflicts of interest and anti-competitive actions in relation to the impact of core procurement on other local distribution company services are directed to SoCalGas and PG&E.
Noncore customers prefer marketers to the local distribution company not because of allegedly lower commodity procurement prices being offered by competitive marketers, but rather because of the costs paid by core customers for bundled firm interstate transportation costs and storage, and because the local distribution company is precluded by the Commission from offering procurement services to noncore customers on a similar basis to marketers.  Edison’s witness Cushnie  stated that “The big reason I think why the noncore market has been a very competitive market in the way we’ve defined competition here today is that the core had a defined reservation of storage and interstate pipeline capacity that it pays for.  The noncore did not.”  It appears that utility affiliates are able to become significant marketers to noncore customers when they are able to enter the market on a similar basis as other marketers.  Once transportation and commodity costs are unbundled, marketers should be able to compete for core customers in the same way they compete for noncore customers.
Enron argues that core procurement competition does not really exist, because the market share of core aggregators is relatively small.  Enron concludes that it is necessary to remove the local distribution companies from the market.  While it is true that precluding the local distribution company from providing core commodity service would increase the market share of other providers, we find that there is an opportunity for procurement competition without taking such a drastic step.  In addition, Enron does not, nor did any party allege, that the local distribution companies had taken anti-competitive actions against core aggregators.
It appears that there are several reasons that participation in the core aggregation program is small.  First, transaction costs have become prohibitively high for smaller customers.  ORA states that the smallest noncore customer consumes 500 times the average gas supply of a residential customer.  At the same time, the potential savings for smaller core gas customers which might be offered by a marketer are very slim.  PG&E demonstrates that even a 5% reduction in a typical bill for the gas commodity, in itself difficult to achieve, would only result in savings of 57 cents per month for an average residential customer. The challenge for other providers is enhanced because marketers competing only for gas procurement supplies must build in a profit margin, in addition to their operating expenses, while the local distribution companies do not stand to profit from gas procurement, except to the extent that a shareholder reward occurs under the gas PBR.
In addition, it is difficult to make large purchases of gas at low prices and requires a sophisticated firm with extensive knowledge and experience and with the purchasing flexibility allowed by gas storage.  There may be obstacles to competing for all services along the “value chain,” i.e. the chain of services needed to ultimately supply gas to core customers: transportation, storage, procurement, distribution, revenue cycle services, etc.
The problem is not so much in core procurement itself, but in other areas of the gas delivery system.  It is possible that if we make modifications to the gas industry structure in California to allow competition all along the “value chain,” or along substantial portions, this may allow a greater degree of competition for core procurement customers, too.
Other parties testify that even after interstate capacity costs have been unbundled by PG&E and SDG&E, there has not been a significant upsurge in core aggregation.  At the same time, we agree with the testimony of Edison that “…there’s a real big difference between unbundling and removing the local distribution company from the default core procurement role.”
ORA suggests that if the Commission is intent on removing the local distribution companies from core procurement, then the core procurement function should be re-examined at some later date, once the market share of marketers exceeded some threshold amount.  PG&E appears to be open to such a suggestion.  Utilicorp agrees with such an approach and suggests a threshold amount of 20% of the market, but didn’t specify whether this referred to the number of customers or to the percentage of core load.  We recommend the re-examination of local distribution company core procurement and the default provider function if the market share exceeds 30% of the number of customers, but even at that point we may be reluctant to eliminate local distribution company procurement as an option for customers.  We have not heard any clamoring or complaints from smaller core customers or their representatives for the removal of local distribution company procurement as an option.
2.	Core Aggregation
In addition to the steps proposed above designed to increase competition for transmission and storage, there are two steps we can recommend in order to enhance customer choice and competition for the core procurement market.  First, we recommend the elimination of the core aggregation threshold of 20,800 therms per months, or in the case of PG&E under the Gas Accord, 10,000 therms per month.  Second, we recommend the elimination of the 10% core cap on overall Core Aggregation Transportation Program (CAT) participation.
As we discussed in D.98-08-030, the core aggregation threshold had two purposes: first, to restrict eligibility to the larger customers who were likely best equipped to participate in the competitive market; second, to ease the administrative burden on the utilities during the initial phase of the core aggregation program.  The core cap was designed to provide utilities with customer and load stability and at the same time provide an opportunity to test the competitive supply market.
The core aggregation program is no longer experimental. Competition for core procurement has matured and customers are now much more aware of such options.  Utilities have developed transaction and information systems able to accommodate transactions involving all core customers, and the distinction between core and noncore customers is less clear than in 1990, when the program was initially established.
Lifting the core aggregation threshold and core participation cap will expand the competitive options available to residential and small commercial customers.  In the case of PG&E, we recommend that this change occur sooner than the expiration of the Gas Accord.  This would necessitate a change in the term core “aggregation” since a marketer would no longer have to aggregate customers at all.  However, we reiterate our previously-stated intention to ensure that appropriate consumer protection measures are in place before existing limits are removed.  We discuss our proposal for such measures below.
In addition, we recommend the unbundling of interstate capacity costs for SoCalGas.  PG&E and SDG&E have already unbundled such costs.  Again, there was no opposition to this measure.  This may enhance the opportunities for competition for core customers, as marketers search for ways to beat the SoCalGas costs for interstate transportation.
Together, these measures would allow head-to-head competition for core customers of any size.  While these measures may not necessarily result in an immediate significant increase in core marketers share of the market, they nonetheless remove obstacles.
SoCalGas also suggests that it is ready to unbundle about half of its 70 BCF of core storage.  Other parties also support the unbundling of storage costs.  At the same time, the local distribution companies oppose divesting any additional storage assets.  ORA proposes that the local distribution companies divest storage in excess of core requirements.
As stated elsewhere in this decision, we intend to explore the unbundling of SoCalGas’ core storage requirements in the cost-benefit phase of this proceeding.  Storage costs are another significant element in the total cost of services provided to core customers.  Storage services help to provide core customers with reliable service and gas cost savings.  We discuss the issue of divestiture of storage assets beyond core needs elsewhere in this decision.
3.	Treatment of Core Load for Operational Purposes and Balancing
Some parties believe that the core class has rights beyond those available to noncore customers which aren’t appropriate in a competitive market, and which could allow the local distribution companies to discriminate against other customers since the local distribution companies stand to profit from the gas PBRs, incremental use of storage, or use of hub services.  This appears to be mainly an issue on the SoCalGas system.  Core customers are already supposed to be treated like any other customer on the PG&E system, are clearly liable for OFO penalties, and hub service revenues are not included in the CPIM.  There is some disagreement as to whether SoCalGas essentially uses core load to balance the SoCalGas system.
There does not appear to be any significant reason why core customers can’t be treated on the same terms as any other customer with firm rights.  ORA recommends “a clear separation between utility core procurement and utility transmission and distribution operations” (ORA Opening Brief, pg. 6) and that “…all SoCalGas and SDG&E storage and reliability services be unbundled from core transportation rates…” (ORA opening Brief, pg. 4)
Core aggregators are subject to imbalance penalties, so core load served by local distribution companies should be subject to the same terms as any other customer, except in emergency situations.  However, this may result in additional costs being borne by other customer groups and could result in the need for heightened balancing requirements. We recommend that this issue be examined in the cost/benefit phase.
4.	Elimination of Core/Noncore Distinction
Utilicorp recommends the elimination of the core and noncore class distinction, and replacement of those classes with firm and nonfirm classes.  While this is an interesting proposition, it is unclear what is to be gained from such an exercise. Core customers are served on a firm basis, and noncore customers on the PG&E system already have the option of obtaining firm or nonfirm service.  This is possible because PG&E has unbundled its system to a greater degree than SoCalGas or SDG&E.  Further, while we will be analyzing the possible unbundling of SoCalGas’ transmission, storage, and distribution costs, it is not clear at this point whether it makes sense to unbundle the intrastate systems of SoCalGas or SDG&E.
If we would unbundle various costs, customers might then have the option of choosing which services they wish to take on a firm or nonfirm basis.  Before taking up the establishment of a firm/nonfirm classification system, we would first need to establish a structure in which it makes sense.  We do not recommend proceeding with Utilicorp’s proposal at this time, but it may be ripe for consideration in the future.
5.	Core Subscription
Noncore customers who choose to continue purchasing gas directly from the local distribution company must make a commitment for a certain period of time.  Under our core subscription rules, we require a two-year commitment.  Under the Gas Accord, the core subscription program is being phased out.  Core subscription customers may continue purchasing gas directly from PG&E up to March 2001.  At that time, they must either stop purchasing gas from PG&E or must become permanent core customers.
Many noncore customers still purchase their gas directly from the local distribution companies, but these tend to be the smallest noncore customers.  For example, on the PG&E system over 12% of the 1100 noncore customers prefer core subscription service, but less than 2% of total noncore load is served by PG&E core subscription.  ORA recommends that the Commission phase out the local distribution company core procurement service for noncore customers by April 1, 2001, in coordination with the Gas Accord.
We agree with this recommendation.  This will allow core subscription customers adequate time to assess whether they want to become core customers or to make arrangements for self-procurement of their gas.  Core service will no longer be offered to noncore customers on a temporary basis.  Noncore customers that are large enough to make their own purchasing needs, are able to take advantage of price opportunities, and generally do not require default service should not be allowed to take temporary local distribution company procurement service.  Noncore customers who want to continue taking a bundled local distribution company service should become core customers.
E.	Improving the Flow of Information Related to Market Transactions
Natural gas utility customers have already worked extensively, in the hearings and elsewhere, to communicate what they need to know from the utilities in order to function more effectively in the natural gas marketplace.  To differing degrees, the utilities have responded to customers’ concerns and have provided some of the requested information.  Some differences remain.  At issue here is whether the information currently provided by the utility is sufficient to allow competitors and customers to function effectively and efficiently in natural gas markets, and whether the utilities should be required to provide certain additional information.
Based on the extensive testimony received in this proceeding, we believe customers and competitors need more data about the utilities’ transportation and storage services than is currently being provided.  We are not prepared at this time to prescribe in detail the information that should be provided to market participants.  We believe the market participants are best suited to negotiate their information requirements.  However, we will offer guidelines as to the nature of additional information that should be provided and how we expect customers to be able to use it to function effectively and efficiently in the marketplace.
We will ask the interested parties to this proceeding to use the guidelines provided today to begin working together in an effort to agree on gas market disclosure requirements and procedures.  In sum, we believe that all market participants should have equal access to the same operational and market information available to utility employees.  We hope to achieve such parity through the provision of the following elements:  1) technology for customers to access their own real-time information; 2) greater disclosure of the details of market transactions; 3) a mandatory electronic bulletin board to facilitate secondary market transactions for transmission and storage; and 4) system information upon which PG&E and SoCalGas make operational decisions.  If parties wish, we will provide staff assistance in mediating these meetings.  Parties should meet with the goal of completing information standards by July 23, 1999.  We are prepared to rule on any issues not worked out by that date.
We acknowledge that disclosure should not come at the expense of the current utility department’s ability to provide low-cost, high-value services to its customers.  It also should not compromise the utility’s ability to provide safe and reliable service.  We will weigh all these considerations in ruling on any outstanding information issues parties are unable to resolve on their own.
1.	What Market Participants Want to Know
Many parties assert that access to a broader range of market information will satisfy two primary concerns.  First, market participants want to be able to assess California’s natural gas market independently.  Second, they believe the availability of information is necessary to determining whether anti-competitive behavior is taking place.  We discuss each of these concerns in greater detail below.
a)	Information Needed to Prevent Anti-Competitive Behavior
Many parties, including Enron, Edison, Pan Canadian, Calpine, Palo Alto and ORA, argue that up-to-date disclosure of available storage and transportation capacity, and individual storage and transportation transactions, is necessary to ensure that all customers have equal access to such services and competitors are not unfairly disadvantaged.   Calpine in its opening brief summarized this concern:
“PG&E CGT (California Gas Transmission), and PG&E’s other departments, additionally have access to nonpublic information on system operations and customer conditions that may provide competitive advantages over other market participants.  The gas utilities know a customer’s needs and the existing system conditions.  The “inside information” enables these gas utilities to bargain for services from a position of strength, especially in areas of the gas industry where competition is not yet fully developed.  Making this information generally available to market participants, would appropriately minimize or even nullify the competitive advantage PG&E CGT now holds due to regulatory structure.”
Parties focus particular concern on the information available to utility staff members involved in marketing hub services.  Edison points out, for example, that the same PG&E staff is responsible for marketing intrastate transmission, storage and hub services.  This marketing staff has access to the pipeline operation group’s load forecasts broken down by major customer class.  Such information provides utility marketing staff with knowledge, before it is available to the rest of the market, of capacity that is likely to become available, probable system constraints, and, ultimately, the potential value of the services they are marketing.
Edison points to the access PG&E hub services marketing staff has to the details of customer imbalances as another example of inappropriate access to operational information.  Edison observes that, on the 30th day of the month, employees selling hub services have access to a shipper’s cumulative imbalance position through the 29th day of the month.  Knowing if a shipper is long or short on the day before imbalances are to be calculated gives the utility staff an unfair advantage in negotiating any hub services the shipper might need to bring load back into balance.  In response, PG&E points out that customers do not use the highly interruptible hub services for balancing purposes and that only four hub service transactions were recorded during the first six months of the Gas Accord.
Calpine argues that the Commission’s policy on the role of disclosure in an increasingly competitive market should be consistent with that of the FERC, citing the FERC’s position in approving Order 636 in 1991:
“Timely and equal access to any and all information necessary for buyers and sellers to arrange gas sales and capacity re-allocations’ is critical so ‘a pipeline, through a tariff provision or otherwise, does not give its own sales or sales of an affiliate a preference by other gas sellers.” (Calpine Opening Brief at p. 31, reference FERC Order 636 at 30,393)
We agree that information is a powerful tool in preventing potential anti-competitive behavior.  Considering the relative dominance of the gas utilities in providing gas transmission and storage within California, the availability of information to the market becomes critical to participants as well as to regulators evaluating whether anti-competitive behavior is taking place. We are particularly concerned that internal utility departments not have advance knowledge of transmission or storage system operations and key customer information that could provide utilities with an advantage over unregulated competitors or potential competitors in marketing their service(s).
b)	Information to Facilitate an Independent Assessment of the California Natural Gas Market
Several parties, including Calpine, Palo Alto, Enron, Pan Canadian and CGC, want to be able to use their own methods to assess the prevailing transmission and storage conditions at any given time.  Specifically, parties want to know more about price trends and available capacity, status of system operations, and the criteria upon which the utility bases operational decisions, in order to plan their own positions in the market more efficiently.  For example, several parties joined Calpine in requesting access to sufficient information to enable shippers to determine whether PG&E will call an OFO.  Parties generally agreed with Palo Alto that the “essential building blocks of information” that would allow parties to conduct their own independent assessment of market conditions include the following:
•	System deliveries and demand forecasts broken down by major customer class (i.e., core, noncore, electric generation, off-system and shrinkage);
•	Status of the storage market, including actual storage injections and withdrawals, and injection and withdrawal capacity available at any given time during the gas day, broken down by type and amount of storage services; and
•	Operations information, such as timely reporting of line pack and total system receipts and deliveries at each telemetry point and pipeline interconnection, and system inventory;
•	The criteria and forecasting models the utility uses in making operational decisions.
In addition to these “essential building blocks,” Pan Canadian advocates that the utilities provide customers’ own real-time consumption data to allow them to better track their own demand.  Further, Edison, Calpine and Enron maintain that the Commission should require the utilities to provide the same information about intrastate transmission transactions that interstate pipelines regulated by the FERC must make available.  Such information includes an index of customers holding firm capacity, and the amount of capacity, price and duration of all contracts.  They argue further that the utilities should be required to create and maintain an electronic bulletin board that would facilitate intrastate capacity trading.
Parties who advocate disclosure of these market elements maintain that it will allow shippers to plan more effectively to balance their gas deliveries and usage, and enable them to assess the availability and reliability of services.  They argue that the ability to make such individualized assessments will benefit the transportation and storage markets generally, in addition to individual customers.  They state, for example, that if shippers are able to assess the market and adjust supply and demand accordingly, they are more likely to stay in balance and the need for OFOs and the associated transaction and system costs are decreased.  As another example, Edison cites the lack of posting requirements about intrastate secondary markets as a significant barrier to the efficiency of those markets.  Edison argues that posting the details of each transportation and storage transaction would increase market efficiency because such information would provide price discovery and allow market participants to transact with parties other than the local distribution companies.
There are several reasons we believe that more complete market disclosure requirements may be necessary.  First, we see ensuring adequate market information as a pre-requisite to considering many other reforms under consideration in this proceeding. Addressing the frequency of OFOs, moving toward daily balancing, facilitating secondary markets, encouraging competition for the core retail market, and addressing concerns about information flow between internal utility departments all begin with the task of evaluating information needs and resources.
Next, providing information should allow individual shippers to manage their gas flows more efficiently by understanding system conditions, anticipating changes and reacting accordingly.  With adequate real-time data, market participants may be able to perform their own individual calculation of the likelihood of an Operational Flow Order and take any steps needed to reduce their exposure to penalties that would apply if an OFO is called.  Similarly, information about storage service capacity would enable market participants to assess the availability and reliability of market center (hub) services more accurately.  Increased information would also provide a framework for a more efficient gas services market overall by providing to the market price discovery, and allowing market participants to transact with the utility and other parties with greater confidence.  Ultimately, this knowledge should lead to gas utilities and their customers using their resources more efficiently.
Finally, we agree that knowledge about market dynamics is an important competitive tool.  As we have stated earlier in this rulemaking, information is a key element in making all market participants – competitors and customers – more comfortable and confident in participating in the emerging competitive natural gas services industry.  While we have relied on this philosophy primarily in the context of educating small residential and commercial customers about the retail elements of competitive gas services, the concept of ensuring sufficient knowledge and disclosure applies to the wholesale side as well.
2.	Areas of Contention
We focus today on the four primary areas in which the utilities hesitate to provide certain information.
a)	Real-Time information
PG&E and SoCalGas argue that much of the real-time and/or customer-specific information requested is either not available or expensive to provide.  PG&E maintains that requiring it to provide real-time information on available capacity is overly broad and onerous, and points out that it already posts available storage capacity, for example, four times each day.  PG&E does not indicate the reasons why such a request is broad and onerous, or specify the level of costs associated with providing real-time updates on available capacity.
PG&E further notes that it uses automated meter reading (AMR) technology to read its large-volume customers’ meters five times daily, however, it does not read customers’ meters on a continuous basis because it is unnecessary from an operational standpoint and would be too expensive.  PG&E offers to install the appropriate technology, at the customer’s cost, for those shippers who want access to their own consumption data on a real-time basis.
For example, PG&E provided Palo Alto with the option to receive pulses from the PG&E meter from which real time information is available, and Palo Alto has taken advantage of the opportunity.  PG&E argues that individual customers should pay their own costs if they want real time information on the gas they are consuming, since it is not appropriate to charge other customers for the cost of equipment not needed for pipeline operations or customer billing.
Pan Canadian argues that, since PG&E is already equipped to read meters remotely, it shouldn’t ask customers to read their own meters, adding that such activity takes away from customers’ primary business.  The record does not reflect what it would cost to install and maintain such equipment.
Any complete picture of the gas transportation and storage markets must, almost by definition, be as up-to-date as possible.  Customer access to real-time consumption data is consistent with our goals of increased market efficiency and providing competitive tools.  We therefore support the concept that customers who want or need it should have real-time access to their consumption data in order to better manage their pipeline flows.  The record indicates that the necessary technology currently exists to provide such information.
That being said, we agree with PG&E that all customers on the system should not have to pay for potentially expensive equipment they do not use.  In the absence of detailed cost information, the most promising option going forward appears to be for the utilities to make available to any customer, at the customer’s expense, the equipment, technology and training necessary for expanded customer access to timely consumption information.  We are interested in hearing from parties in the cost-benefit phase of this proceeding what it would cost on a per-customer basis to make such access generally available, if those costs vary by customer, and any other relevant information.  We also are interested in learning the specific impediments to providing real-time available capacity updates.
b)	Details of Completed Transactions
The utilities do not believe they should have to disclose the details of completed transactions, including the index of customers holding firm capacity, amount of capacity, price and duration of all contracts requested by customers.  SoCalGas points out that the Commission has issued rules prohibiting utilities from disclosing customer-specific information absent an affirmative consent from the customer.  It cites the following Commission precedent against public disclosure of negotiated contracts:
•	D.92-11-052 (modified by D.93-02-058), in which the Commission allowed the utilities to keep confidential certain information contained in Expedited Application Docket (“EAD”) contracts negotiated by the utilities with individual shippers;
•	Resolutions L-246 and L-251, in which the Commission denied complainant and member of the press requests for disclosure;
•	Pub. Util. Code Section 489.1 (enacted in 1996 in AB 1095), as implemented by D.97-06-110, which provides guidelines to the Commission in granting confidentiality of the terms of negotiated gas utility service contracts;
•	D.97-12-088, which adopted rules governing utility transactions with affiliates; and
•	D.98-03-073, which adopted remedial measures to prevent possible market power in the merger of Pacific Enterprises and Enova Corporation.
SoCalGas states that requiring utility disclosure of customer‑specific information seriously undermines a utility’s ability to offer services competitively.  It argues that, since other unregulated providers with whom utilities compete are not required to make publicly available the details of their transactions, customers who want to keep their transactions private will take their business to utility competitors first.  PG&E adds that its Gas Accord experience to date indicates that customers do not want their transaction details made public.  Calpine and others answer, and PG&E agrees, that concerns about confidentiality can be resolved by coding the information so that only transaction and customer numbers appear.  Pan Canadian witness Cattermole acknowledged in the hearings that, while Pan Canadian did not support disclosure of customer-specific information during the first auction of PG&E’s Redwood line capacity, it might feel differently once markets were competitive.
Finally, SoCalGas maintains that the Commission had the opportunity to require disclosure of specific transaction details in the context of our review of the Pacific Enterprises/Enova merger, and elected not to do so.  SoCalGas believes that decision would foreclose any further consideration of the issue here.
We disagree with SoCalGas.  In this case we are examining statewide concerns based on testimony and comments about evolving market conditions not considered in the Pacific Enterprise/Enova merger or any other utility-specific case.  Our policy on disclosure has changed as the natural gas market in California has evolved.  It is useful to review L-246 and Pub. Util. Code Section 489.1 in the context of the record here.  In L-246 (January 5, 1995) the Commission  concludes that, “…on balance, the public interest in not making these contracts public outweighs the public interest served by disclosure”.  In that resolution the Commission also acknowledged our decision D.94-02-042 on February 16, 1994 in denying a PG&E request to designate contract provisions as confidential:
“We will deny PG&E’s request.  Under our market-based approach to gas transportation, we favor pipelines which are economically justifiable means to reduce gas costs through gas-on-gas competition.  For the gas commodity market to operate efficiently, the participants must have access to information about transportation and other costs. …confidentiality of information might prejudice some negotiations, but the costs of that prejudice are far outweighed by the benefits of an open market.  Secret prices and conditions do not encourage the competitive market we envision.” (L-246 at p. 2, referencing D.94-02-042 at p. 50).
Subsequent to this resolution, the Legislature enacted AB 1095 in 1996, which adopted Pub. Util. Code Section 489.1.  This code section provides that the Commission “may…partially or completely exempt, from the requirements of subdivision (a) of Section 489, contracts negotiated by the gas corporations for service subject to the commission’s jurisdiction, with rates, terms, or conditions differing from the schedules on file with the commission.” (emphasis added).  It further directs the commission to adopt and enforce rules that both consider “the impact of supply contract confidentiality on competitive markets” and require “(1) (r)easonable comparability between contract disclosure requirements applicable to gas corporations and those applicable to competitors pursuant to federal law.”.  In D.97-06-110 we adopted rules that exempt from public inspection certain contracts negotiated by a gas corporation, under specified conditions.  The rules we adopted provided specifically that:
“Section 489.1 does not protect from disclosure that type of information that a gas corporation’s competitor(s) must disclose pursuant to federal law (see, for example, the Federal Energy Regulatory Commission’s discount Reports requirements, 18 C.F.R. paragraph 284.7(c)(6)).  If federal law requires disclosure of a competitor’s information, the gas corporation shall then disclose the same information.”  (D.97-06-110, Appendix A, p. 4)
The Commission is not required to preserve the confidentiality of negotiated gas contracts.  We have elected in certain circumstances to do so in the past, consistent with the statute and our rules, based on our assessment of then-prevailing market conditions.  The record developed here indicates that those conditions are changing.  Like federally-regulated interstate pipelines, PG&E now offers path-specific, tradable firm rights on its transmission system, and firm tradable rights for storage services as part of the Gas Accord.  Later in this decision, we conclude that a similar structure – at least in concept – is a promising option to consider for SoCalGas.  We are concerned that, as Edison witness Cushnie stated, “it is not transparent to the market who the holders of capacity are on the PG&E intrastate transmission system.”  Disclosure of the transaction-specific details requested here by parties is basic and fundamental to an efficient market.  Indeed, as Calpine and Edison noted, the interstate pipelines regulated by the FERC already provide this information, and may soon be required to provide more; we are unaware of significant competitive harm that has resulted from disclosing it.
We believe SoCalGas overstates the concern that potential customers may be put off by the prospect of having the details of their transactions made public.  The concern highlights for us the possibility that unfair competition may already exist vis-à-vis interstate pipelines, to the extent that SoCalGas, for example, competes with Kern River or Mojave Pipeline – both of which must post transaction-specific details.  Further, SoCalGas and PG&E each dominate the storage and transmission markets for natural gas in their respective territories.  As we have stated earlier in this order, shippers currently have few options from which to choose in meeting their gas transportation and storage needs within California.
We have so far declined to require potential competitors to disclose the details of their contracts as a condition of providing service in California but are willing to consider it if necessary to facilitate fair competition.  We are interested in hearing in the cost-benefit phase the implications and impediments to imposing the same requirement uniformly on utilities and their storage and intrastate transmission competitors.  We are also interested in learning what fundamental differences exist, if any, between federally-regulated interstate pipelines and the intrastate transmission and storage that would lead us to conclude that the information disclosure requirements for intrastate pipelines should not be consistent with, or exceed, those for interstate pipelines.
3.	Electronic Bulletin Board
PG&E believes the utilities should not be required to establish a FERC-style electronic bulletin board for the purpose of facilitating secondary market transactions for transmission and storage services.  It argues that the Commission has historically declined to regulate the prices, terms and conditions of secondary market transactions, citing the Commission’s approval of the Gas Accord in D.97-08-055.  PG&E contrasts its interpretation of that decision with the more active regulation of the interstate secondary market asserted by the FERC.
We clarify that the purpose of a utility-sponsored electronic bulletin board is to facilitate disclosure of secondary market transactions.  We are not considering here regulation of the prices, terms and conditions of secondary market transactions, although we may in the future, if market conditions warrant.  Participation in the secondary market transactions through a mandatory electronic bulletin board is consistent with our goals of enhancing market efficiency, preventing anti-competitive behavior, and providing additional competitive tools to the marketplace.  Considering that all secondary market transactions will need to be confirmed through the utility, it is logical to require utilities to provide the electronic bulletin board.  However, we need to understand the costs of providing such a service before determining whether to require its provision.  We ask parties to explore such costs in the next phase of our inquiry.
4.	Demand forecasts broken down by customer class
PG&E has three primary concerns with shippers’ request that it provide the pipeline operator’s demand forecast broken down by major customer class.  First, as we understand it, PG&E’s demand forecasts often (but not always) incorporate information shared voluntarily with the pipeline by certain large-volume customers such as large electric generators and PG&E’s own core procurement group.  PG&E fears that if the utility is required to disclose its demand forecasts, those same customers likely will be reluctant to share their information with the pipeline in order to protect the confidentiality of their respective positions in the marketplace.  The result, PG&E says, could affect reliability because the pipeline operations group would receive less accurate information about expected gas flows and system deliveries.
Second, PG&E joins SoCalGas in maintaining that disclosure of customer class-specific information could potentially increase the costs to certain customers.  As PG&E states in its opening brief,
“PG&E currently has only three customer classes:  core, electric generation (EG), and noncore.  EG is made up of basically two large customers, the plants now owned by Duke Energy, and the plants PG&E expects to sell soon to Southern Energy.  The current EG forecast is based on various sources, including information that the two generators give to CGT in confidence concerning their expected gas flows…(s)imilarly, the core class is made up of PG&E’s Core Gas Procurement Department and core aggregation demand.  Because Core Procurement makes up approximately 95% of core gas sales, disclosure of forecast demand would effectively provide customer specific information about the daily purchase needs of PG&E’s Core Gas Procurement Department…If suppliers know exact information about Core Procurement’s forecast needs on a given day, it will allow them to extract a higher price for such supply.  No customer would want its purchase needs communicated in advance to the rest of the marketplace.”
Palo Alto notes that customers of utility procurement departments would not be put at a disadvantage by this proposal since these departments are large, sophisticated buyers in a very competitive natural gas commodity market.  Enron asserts that knowledge of a party’s demand is not necessarily indicative of that party’s position in the marketplace, since there are many other variables that affect the quantity of gas a buyer may need to purchase.  Pan Canadian points out that any potential seller or competitor to PG&E who wanted to predict the utility core procurement group’s likely position in the marketplace already has access to sufficient information to estimate that position themselves.  Market participants already know core historical load, are aware of the fact that load varies with temperature, and have access to their own sophisticated weather forecast information.  Disclosing the pipeline operator’s demand forecast for the purpose of educating shippers about precise system conditions would therefore not reveal to the marketplace significant incremental information about the core or other large users’ purchase positions that the market could not already figure out for itself.
Furthermore, Pan Canadian argues, as core aggregators gain market share, the share attributable to PG&E’s core load will presumably decline – and along with it, the ability to determine its likely position in the market.  Finally, Pan Canadian believes that PG&E has overstated the degree to which the market will be able to determine the specific identity and position of Duke Energy and Southern Energy if PG&E posts demand forecasts of the EG class as a whole.  Pan Canadian reminds us that the data for the EG class includes, in addition to recently and not-yet-sold utility electric generation plants, qualifying facilities (QFs) and other cogeneration plants; the data for the class as a whole would therefore not permit analysis of individual generator’s positions.
Finally, PG&E argues that non-utility competitors offering hub services don’t need access to load forecast information that is available internally to utility gas transmission department staff.  It maintains that this information is not even valuable to PG&E because of the many alternatives available to potential hub services customers, and that no information walls should be set up between hub services and other PG&E departments.  However, PG&E states that internal utility staff should still have access to load forecast information because creating internal information walls may impair the availability of transactions desired by customers and the operator’s ability to efficiently manage the pipeline.  Pan Canadian points out the PG&E’s reluctance to make available load forecasts by customer class demonstrates that the information does have value.
We agree with Enron’s assertion that providing more information now is the least costly and least intrusive means of addressing some of the current concerns about potential utility anti-competitive behavior and market inefficiency.  It is not up to utilities to determine what information is useful or valuable.  Market participants should have access to the information that best suits their respective needs, as long as safety and reliability, and the utility’s ability to procure gas economically on behalf of their customers are not compromised.
It is important that any entity competing to provide a natural gas service have access to exactly the same information about demand forecasts and the existing system conditions that is available to utility staff.  Information retained by the utility that enhances a utility department’s ability to provide competitive or potentially competitive services should not be considered proprietary by the utility if it provides a competitive advantage to the utility in offering that service.  The record indicates that the utility may gain a competitive edge, especially with regard to the offering of hub services and storage, by retaining the forecast information upon which the transmission group bases its operational decisions.
We are not persuaded that disaggregating demand forecast information will create a disadvantage for any customer, including the core.  Disclosing the customer class-specific demand forecast, even if it does imply a specific customer’s forecast demand, does not create an advantage for a seller unless the seller knows where the buyer’s other constraints are.  The point at which a buyer tips its hand in the marketplace is at the time when it actually requests a specific quantity of gas – and buyers are already doing that now.  We agree with Pan Canadian that, since the market already has access to historical usage, weather and other potential variables, disclosing the transmission group’s forecast demand by customer class would not harm any particular customer.  Although such information may lend a small degree of additional precision about customer demand, providing it will also contribute greater efficiency and certainty to market participants individually and to the market as a whole.
Finally, with regard to PG&E’s concern that disclosure could result in shipper reluctance to share their own demand forecasts with the utility transmission operator, we do not believe that any particular customer would have an incentive to lessen the reliability or precision of its communications with the pipeline operator.
The promising options for further consideration that we identify in this decision envision clearer separation between existing utility departments and services but fall short of a structure in which the utility would divest itself of any service it currently provides.  Absent such a structural solution, information plays a critical role in the competitive, efficient market we hope to promote.  As we see it, there are three alternatives available.  First, we could propose a structural solution that would eliminate the utility’s role in one or more services, such as core procurement, and thereby eliminate the concern that information is inappropriately shared internally.  Second, we can require the utilities to provide the specific information as discussed above, including real-time information, transaction-specific details, mandatory electronic bulletin boards, and demand forecasts disaggregated by customer class.  Third, we can encourage the utilities to use the discussion provided here to work with interested parties to arrive at alternative, but mutually acceptable standards of communicating to the market sufficient information for it to function efficiently, confidently and competitively.  Either of these last two options would be acceptable to us.  If parties are unable to resolve this issue by July 23, we will explore this issue further in the cost-benefit phase.  In that effort we will focus specifically on such issues as how customer class specific information would help shippers avoid OFOs, why utility procurement could be harmed by its disclosure, comparability of information the interstate pipelines are required by the FERC to provide, other confidentiality concerns, and what alternatives may exist.
F.	Accountability for System Safety and Meter Choice
We have yet to hold hearings on the safety implications of any of the change options.  However, there is a compelling argument for maintaining the relatively clear accountability that the natural gas distribution companies have for the safety of the gas delivery system through the distribution system to the burner tip.  We do not currently believe that it is a promising option to encourage the cost or rate separation of meter reading or servicing,  or of what have been referred to as after-meter services.  Distribution utilities should continue to provide these services as part of a bundled distribution service.
At the same time, it may not be inconsistent with such safety concerns to require the distribution company to install and subsequently service meters other than those normally provided by the utility.  Any meter would have to meet appropriate safety standards and utilize standardized information protocols.  Affected stakeholders would work together to develop these standards.  With these limitations, we view the competitive provision of meters to be a promising option, consistent with our goal of ensuring safe and reliable service, as well as our objective of removing unnecessary barriers to entry into various components of the natural gas service market.  We will ask parties to explore this option further in the cost/benefit phase.
G.	Billing Options
In D.98-08-030, the Commission also observed that there is good reason to consider opening the natural gas bill rendering, remittance processing, and collections services functions (billing) so that competing gas and electric providers can choose to provide a consolidated bill for gas and electricity and so that the customers of such providers will not face duplicative charges for the billing function.  In addition, most customers who purchase natural gas from entities other than the utilities now receive redundant bills from the distribution utility and the gas provider.  This may be an inefficient result, where the customer only wants a single, consolidated bill yet  is saddled with the cost of two bills.
We agree with these observations and continue to feel that it may be appropriate for the natural gas utilities to provide billing options similar to those currently offered on the electric side.  Competing service providers may want to offer their customers complete energy service, which could include both gas and electricity.  We should make it just as possible for an electricity provider to bill its customers for gas service as it would be for a gas provider to bill for electric service.  We include this as a promising option for further study and  specifically look forward to examining the cost of system conversion and potential labor impacts associated with providing competitive billing and other services in the cost/benefit phase.
H.	Cost and Rate Separation
In D. 98-08-030, the Commission recognized that, with some differences, both PG&E and SoCalGas already offer separate rates for procurement, storage, and interstate transportation.  As we continue the movement toward the broader offering of competitive services, it is important to ensure that all costs are assigned to the appropriate function.  To achieve this goal, it is as important today as it was when we issued D.98-08-030 that we examine each utility’s total revenue requirement and understand where each dollar should be assigned on a functional basis, whether those costs are fixed or variable, specific or common.  Then, when we have determined whether and the extent to which various service components will be competitively provided, the utilities will be able to implement separate rates for those services and assure us that no charges have been left in any functional category by default.
As we indicated when we expressed our initial goals in this proceeding, the offering of separate rates for competitive or optional services is critical to a customer’s ability to make an informed, efficient business decision.  We continue to find that it is a promising option to consider proposing to the legislature that natural gas costs and rates be separated in the manner described in D.98-08-030, with the exception of meter-related and after-meter services.
TURN cautions that the Commission should not further evaluate the merits of rate separation of various components of core service until it can obtain cost separation data from the utilities.  It is incumbent on TURN and other interested parties to identify the information they need and to issue data requests as early as possible.  We expect the utilities to respond promptly and completely to any such requests.
I.	Enhancing Consumer Protections for Core Customers
Here, we address the consumer protection issues associated with expanding the competitive options available to core natural gas customers.  This aspect of this decision serves only as a vehicle for reporting our suggestions to the Legislature.  We propose a program that enables residential and small commercial customers to make informed decisions regarding these competitive options, protect themselves from unscrupulous providers, and seek assistance if problems arise.
In this proceeding, the Commission has been exploring the criteria it should use when establishing consumer protection rules for the natural gas industry.  In D. 98-08-030, the Commission concluded that 1) it is necessary to have consumer protection rules in place before the core aggregation transport program restrictions are lifted, and 2) the consumer protection rules established for the natural gas industry must be consistent, as appropriate, with protections established by the Commission for its other restructured, regulated industries (p. 16).
We recognize the need to refrain from imposing unfamiliar or burdensome rules that could hamper the development of the market and of innovative products and services.  To that end, we propose a consumer protection program for the natural gas industry that is consistent with the program established for the telecommunications and electric industries.
Consistency of rules among industries achieves several objectives.  Providers offering energy and telecommunications products and services will benefit from operating under similar consumer protection rules.  Consistent rules will assist consumers learning to shop for these competitive services, enable them to detect illegal business activities, and understand their legal recourse for complaint or dispute resolution.
We recommend the adoption of a number of standards designed to protect consumers from unfair or abusive marketing practices, assist them in understanding their options, rights and recourse, and allow consumers to feel confident about participating in the competitive market.
When it opened R.98-01-011, the Commission ordered the utility respondents and invited other interested parties to answer specific questions listed in the rulemaking.  These included two questions addressing the need for consumer protections in the natural gas industry similar to those enacted for the electric industry:
23. In Chapter VII, the report emphasizes the need to have consumer protections which are similar to those in the electric industry.  Is this necessary? Why or why not? Are there other protections which should be considered?
24. Are there other state agencies or other entities better positioned to ensure consumer protection and monitor for customer fraud and other marketing abuses? 
The Commission used parties’ responses to these questions as the framework for portions of D. 98-08-030 in which the Commission determined that consumer protections consistent with those established for other regulated industries should be in place prior to lifting current restrictions for the core aggregation program.  The Commission proposed several key elements of a natural gas consumer protection program:
•	A screening process for providers
•	Service provider registration
•	Third-Party Verification
•	A Customer Education Program
•	A complaint resolution process
•	Written Notice and Disclosure
Pursuant to direction from the Commission, the Energy Division developed proposed consumer protection rules and served on parties on October 15, 1998.  The following parties filed written comments on November 16, 1998: the California Small Business Association and California’s Small Business Roundtable (Small Business), the Coalition of California Utility Employees and the Southern California Gas Workers’ Council, Enron Energy Services Inc. and Enron Capital & Trade Resources Corp, Green Mountain Energy Resources L.L.C., NorAm Energy Management Inc., the Office of Ratepayer Advocates, San Diego Gas & Electric and Southern California Gas Company, Southern California Edison, The Utility Reform Network; joint comments were received from Pacific Gas and Electric, Greenlining, and the Latino Issues Forum.
We have reviewed those comments and now address the issues raised in the staff report and by the parties.  Pursuant to Pub. Util. Code Section 328 (Senate Bill 1602 in the 1997-98 legislative session), we cannot enact any new consumer protection standards for core customers this year.  We plan in the very near future to submit a report to the Legislature offering our proposals for enhancing consumer protections for natural gas consumers and seeking legislative procedural guidance.
1.	Commission Authority Over Consumer Protection Issues
Can we adopt consumer protection rules over non-utility gas providers under our existing authority?  The Energy Division identifies the need for legislation conferring authority to the Commission to impose and enforce consumer protection rules on non-utility gas providers.  In the absence of such legislation, staff believes that provider compliance with Commission consumer protection standards would be voluntary.  Consumers subjected to fraudulent or deceptive marketing practices would have no recourse through the Commission’s existing complaint process.  The Commission would have no authority to investigate consumers’ allegations of unsafe or unfair business practices by non-utility gas providers, or to enact operational standards to ensure provider competence and public safety.
Many parties point out that consumer protection legislation, Senate Bill 477, was enacted in 1997 to establish consumer protection standards for the competitive electric industry.  Consumer protection issues were also addressed in preceding electric restructuring legislation: Assembly Bill 1890.  Together, these bills authorized the Commission to establish and enforce such standards as provider registration, a written notice disclosing the price, terms and conditions of the service offering, third party verification, financial, technical, and operational requirements, and a complaint resolution process.
Most parties submitting comments agree on the need for similar enabling legislation for the competitive gas industry, particularly with respect to registration of gas service providers.
PG&E, Greenlining and Latino Issues Forum argue that the Commission could establish and enforce consumer protection rules for gas service providers under its existing authority to regulate gas corporations, including those managing gas plant, citing authority under Sections 221 and 222 of the Pub. Util. Code Section 222 defines gas corporations to include “every corporation or person owning, controlling, operating, or managing any gas plant for compensation within this state…” Section 221 defines “gas plant” to include “all real estate, fixtures, and personal property, owned, controlled, operated, or managed in connection with or to facilitate the production, generation, transmission, delivery, underground storage, or furnishing of gas…”  Joint comments filed by SDG&E and SoCalGas indicate that the CPUC may exert authority over gas service providers as public utilities.
Enron agrees with the Energy Division that the Commission may not currently have jurisdiction to regulate gas sellers or marketers.  Enron interprets Section 222 to confer to the Commission jurisdiction over entities owning or operating natural gas plant.  Enron observes that many natural gas marketers engaged in gas marketing in California do not own such facilities, and are not subject to regulation.  Enron observes that the FERC has issued a “blanket certificate” authorizing all persons to engage in natural gas sales for resale in interstate commerce, and asserts this action was taken to avoid non-cost-effective regulation of such entities.
NorAm agrees with the staff report that the Commission would need to seek legislation similar to AB 1890 and SB 477 for mandatory, rather than voluntary compliance.  ORA concurs that legislation may be the most efficient way to impose and enforce consumer protection rules on non-utility gas providers.  
We believe the consumer protections outlined below will extend our practice of protecting utility consumers by supplying natural gas customers with the tools to make confident, educated choices about natural gas services.  We look to the Legislature to enact in this session legislation codifying the proposals discussed below.
2.	Consumer Protection Elements
a)	Gas Service Provider Registration
Registration of gas service providers serves several purposes.  We noted in our Interim Opinion that registration of providers contributes to consumer education and confidence in the choices available to them.  A publicly-available database of registered providers offers consumers information about companies that might otherwise be unfamiliar to them.  The registration process can ensure that registered providers have met a minimum level of professional responsibility.  A registration requirement creates an opportunity for the use of suspension or revocation to support enforcement efforts aimed against unscrupulous providers.
The Energy Division Report describes a program where, in the absence of legislation conferring jurisdictional authority to the Commission,  providers who voluntarily agree to comply with the Commission’s registration requirements, minimum standards, complaint resolution, and written disclosure would be placed on the Commission’s list of approved providers.  This list would be available to consumers on the Commission’s website and through consumer education activities.  Under a voluntary registration program, a provider could remove itself from the list of approved providers at any time and yet continue to provide services to core customers.
In joint comments, SDG&E and SoCalGas express doubt as to the Commission’s present authority to sanction those providers registered under a voluntary program.
ORA notes that an effective registration program serves to protect consumers from unscrupulous providers, and provides a process to suspend or revoke entities not in compliance with the law.  ORA further contends that while legitimate gas service providers may register with the Commission, unscrupulous providers, registered or not, may engage in fraudulent activities that the Commission, without legislative mandate, will have no authority to stop.
Joint comments filed by the Coalition of California Utility Employees and the Southern California Gas Workers Council express concern that a voluntary program creates the impression among consumers that the Commission is actively engaged in protecting against fraudulent activities, when in fact, it would be powerless to prevent unscrupulous providers from entering the market.
Enron and ORA both caution the Commission against publishing a list of “approved providers,” contending that a government agency should not create the impression that it endorses a company’s products.  Enron contends that consumers will interpret Commission “approval” of providers to imply that the government thoroughly investigates each registrant and guarantees its soundness.
We caution that a registration process should not be viewed as an attempt to endorse specific providers, but should establish requirements to deter undesirable business practices and screen out potentially unscrupulous firms.  We believe that the Commission’s registration process should establish a set of standards for gas service providers consistent with those currently in place for electric service providers.  Provider registration enables consumers to feel confident that registered firms have met the minimum criteria to provide commodity service.
We agree with parties that under a voluntary registration program, the Commission may have very little authority to prohibit market participation by a firm electing not to adhere to the Commission’s requirements. Under a voluntary program, the Commission may be able to respond to evidence of unscrupulous conduct by doing little more than canceling a firm’s registration.  The firm would be free to continue business as usual.  By providing the Commission with clear authority to oversee a mandatory registration program the Legislature would ensure that consumers have protection against such providers.
(1)	Who should register?
Another threshold issue to be determined is which entities should be required to register with the Commission.  The Division of Strategic Planning noted in Strategies for Natural Gas Reform that “Requiring all energy service providers, including those who offer natural gas services to residential and small commercial customers, to register with the Commission will enhance the Commission’s ability to protect energy consumers and monitor for market abuse trends” (p. 96).  The program proposed by the Energy Division mandates registration for all entities, including marketers, brokers, aggregators, and other sellers, that sell natural gas and metering services to residential and small commercial customers.  Natural gas utilities and public agencies offering service within their own jurisdictions would be exempt from the registration requirement.
Most parties agree that entities intending to offer gas service to residential and small commercial customers should be required to register with the Commission, observing that this policy is consistent with the registration process for electric service providers.
SDG&E and SoCalGas assert that in the interest of public safety, the Commission should register all entities, regardless of the type of service offered or class of customers served.
Small Businesses agrees that gas corporations and public agencies offering gas service within their own jurisdiction or the service territory of a publicly-owned gas utility should not be required to register.
NorAm raises the issue of who is considered a “small commercial customer,” and urges the Commission to adopt a definition based on annual consumption rather than a core vs. noncore customer classification.  NorAm points to the Massachusetts model, which uses annual consumption between 5000 and 10,000 therms as a separation point between small and large commercial customer class.  PG&E, Greenlining and Latino Issues Forum also recommend that the Commission establish a more precise definition of “small commercial customer."
Consistent with our mission to protect small consumers, we believe that the registration requirements and consumer protection rules proposed in this decision should apply to gas service providers intending to sell commodity service to residential and small commercial customers.  We agree with the Energy Division and other parties that large commercial, industrial and agricultural customers are already familiar with analyzing energy needs, evaluating competitive offers and litigating disputes through the court system.  It is the small customer segment of the market that must be protected from deceptive or unfair business practices, given sufficient information to make appropriate choices, and provided with an easily-accessible forum for complaint resolution.  Additionally, our experience in other regulated industries indicates that most cases of consumer abuse involve residential and small commercial customers.
(2)	Registration Procedures
We recommend that registration procedures should include the review of application and necessary documentation, issuance of registration numbers, the creation of a database suitable for posting on the Commission’s website, and completion of background checks in conjunction with the Commission’s Consumer Services Division.
The Energy Division’s proposed registration application requires applicants to provide:
•	All legal or other entity names, including DBA or fictitious business name and proof of appropriate filings to retain stated entity names
•	Type of business entity: corporation, partnership, sole proprietor
•	Mailing address, street location, and telephone contact information
•	Majority owner or controlling person or entity
•	Provider-type: marketer, aggregator, broker or other
•	Affiliate entities
•	Customer class, geographic location and number of customers the gas service provider intends to serve
•	A copy of an executed service agreement with the local distribution company serving customers in the applicable territory
•	Key technical and operational personnel and descriptions of each person’s experience in providing related services
•	The entity’s customer notice detailing its price, terms and conditions of service
•	Disclosure of criminal conviction related to consumer fraud, felonies of any kind
•	A full set of fingerprints of the entity’s principal officers
•	Information related to other services the entity plans to offer, such as metering, after-meter, electric or telecommunications
Many of the parties commented on specific application line items, such as the fingerprint requirement, disclosure of affiliate entities, information relating to other types of service offers, and the number of customers a gas service provider plans to serve.  One party raises the issue of requiring entities to provide timely updates should any changes occur to a gas service provider’s previously-submitted information.
Green Mountain objects to the request for the number of customers the gas service provider intends to serve, contending that the information is not useful to potential customers, nor is it needed to determine the size of an applicant’s security deposit.
Green Mountain and NorAm each object to the proposed fingerprint requirement. Green Mountain questions the value of the fingerprint requirement, stating that unscrupulous providers would be able to “manipulate compliance.”  If the Commission adopts the fingerprint requirement, Green Mountain and Enron each support the Energy Division proposal limiting fingerprinting to principal officers, rather than officers and directors.
NorAm objects to the proposed fingerprint requirement as time-consuming and unnecessary, contending that disclosure of the driver’s license and Social Security number of a firm’s principal officers should be sufficient to run background checks.  NorAm observes that legislation will be required for the Commission to obtain a national criminal history record check from the FBI.
Enron asserts that by requiring a firm to obtain a service agreement with the local distribution company prior to registering with the Commission, the utility has the ability to delay the provider’s marketing efforts.  Enron does not object to a requirement mandating a service agreement prior to commencing service, but believes new entrants are placed at a disadvantage by requiring the agreement as a prerequisite to granting registration.  NorAm agrees with Enron that a competing provider should be allowed to register regardless of whether it has obtained a service agreement with a local distribution company, but cautions that a competitor should not be permitted to sign up customers before it has filed with the Commission a signed service agreement.
Enron objects to the proposed requirement that competing firms provide information about other types of services they plan to offer.  They argue that the Commission should not require information about services over which it has no jurisdiction, but should limit the request for information to other regulated services, such as electric or telecommunication services.  Additionally, Enron urges the Commission to consider the impact of the registration process on entry and transactions costs.
NorAm notes that the requirement for applicants to provide a list of affiliated entities could be cumbersome for large companies to compile and might reveal confidential information.  NorAm proposes that a gas service providers owned by or affiliated with publicly-traded companies be allowed to reference its Form 10-K filed with the Securities and Exchange Commission (SEC.)
Small Business argues that the registration program should prevent the use of misleading or deceptive names.
ORA asserts that registration enforcement procedures should be instituted. Gas service providers should be required to update their registration forms to note any changes or face suspension/revocation.  The registration form should state that failure to maintain registration requirements, including an executed service agreement, would  jeopardize the gas service provider’s operating authority, and could result in suspension and/or revocation of registration.  Any change in registration information should be reported to the Commission within five days by way of an updated registration form.
The purpose of requesting specific information from each registrant is two-fold.  First, it allows a consumer to learn more about the entities under consideration for purchase of commodity and other services.  Second, it provides us with criteria to evaluate a registrant’s technical and operational capabilities.  Both serve as protective screening mechanisms to ensure a provider’s capability and genuine intent to adequately serve its customers.
We are of the opinion that the fingerprint requirement is a necessary element to conduct background checks on registrants.  In-state background checks obtained from the California Department of Justice have proved beneficial in determining the eligibility of registrants in the electric provider registration program.  Additionally, at a later date, the Commission may need to obtain a national background check from the Federal Bureau of Investigations.  The time spent by registrants  procuring sets of fingerprints, and by Commission staff authenticating the submittals, ensures that valuable protections are provided to consumers.
We agree with staff and parties that fingerprinting should be limited to principal officers, rather than officers and directors.  This will help to alleviate the concern that the fingerprinting process is burdensome and time-consuming.
We turn to the argument put forth by Enron and NorAm that requiring an applicant to obtain a service agreement with the local distribution company as a condition of registering with the Commission disadvantages new entrants and hampers marketing efforts.  We believe that consumers learning to shop for gas service should be able to refer to a list of providers who meet all of the Commission’s requirements to provide commodity service at the time of registration, rather than provisionally or incrementally.  Further, we question whether a competing firm should represent itself as a viable company through its marketing efforts if it has not demonstrated its actual ability to deliver gas service through the utility’s gas distribution system.  We therefore support the requirement that a gas service provider sign a service agreement with the local distribution company prior to obtaining registration with the Commission.
NorAm raises the concern that the proposed affiliate disclosure requirement could reveal confidential information and be burdensome for large companies to compile.  We have no objection to the inclusion of an applicant’s Form 10K, but emphasize that the applicant should list all affiliate companies, whether or not they are publicly traded.
We recognize that requiring registrants to provide the Commission with all entity names, including DBA(s) or fictitious business name(s) may not alleviate the concern expressed by Small Business regarding misleading or deceptive names.  However, when viewed in combination with the mandatory disclosure notice and third party verification requirements, we believe consumers will be provided with adequate information about the entity offering gas service.
We acknowledge Enron’s objection to the application’s request for information regarding other services offered by a registered gas service provider.  We anticipate that providers will offer several types of service, giving consumers the opportunity to re-bundle individual energy services, and benefit from convergence in these and other retail markets.  Requiring this information will assist us in our effort to provide meaningful consumer education and information services about their choices in the competitive markets.
We agree with Green Mountain’s assertion that the request for the number of customers the applicant plans to serve is unnecessary. This requirement will be removed from the application form.
(3)	Standards of Technical, Operational and Financial Capability
In Decision D. 98-08-030, we stated our support for a process that would screen gas service providers, to assure consumers that registered gas service providers meet minimum levels of financial viability, technical capability or experience, and ethical conduct.  The staff report also discusses the need to adopt standards that will ensure that competing firms are 1) technically proficient to offer the contracted service in a safe and responsible manner; 2) capable of providing a reasonable level of operational support and customer service; and 3) financially solvent.  Staff proposes criteria that will allow registrants to demonstrate the ability to meet these standards.
(a)	Financial Viability
To establish proof of financial viability, the Energy Division  recommends requiring gas service providers to post a security deposit or financial guarantee bond, the amount of which would increase relative to the growth of a firm’s customer base.  The deposit or bond would demonstrate that the firm was able to secure the asset, and ensure that customers could obtain restitution, if necessary, as a result of the complaint resolution process.
Enron proposes that the Commission accept as proof of financial viability an “acceptable investment grade credit rating level issued by independent rating agency.”  Enron suggest that the Commission require deposits or bonds only for firms that cannot demonstrate an acceptable credit rating, arguing that to do more would impose  unnecessary cost and serve as a barrier to entry.
NorAm, Green Mountain, SDG&E and SoCalGas suggest that the Commission adopt deposit standards and amounts similar to those set forth in D. 98-03-072, with a minimum deposit or bond of $25,000, increasing in stages up to $100,000 for firms serving more than 1,000 customers.
Green Mountain proposes an alternate method for calculating the size of the deposit.  It recommends that the Commission allow a single company registering as both an electric and gas energy service provider to post one deposit, based on the total number of customers, for a maximum of $100,000.  Additionally, Green Mountain requests that gas service providers be able to meet the financial viability requirement by submitting either a cashier’s check, performance bond, corporate guarantee or bank letter of credit.
We must ensure that consumers are provided with adequate compensatory recourse in the event a firm fails to provide the agreed-upon commodity or service.  Requiring firms to post a minimum security deposit provides adequate recourse and ensures the financial viability of the provider.  Accepting a credit rating issued by an independent rating agency would not accomplish the goal of ensuring adequate recourse, and eliminates one element of a gas service provider’s financial incentive to perform.
In D. 99-05-034, we concluded that corporate guarantees and  letters of credit comprise insufficient means of meeting the financial viability requirement because neither would provide consumers with adequate recourse, and both would require Commission staff to determine the financial strength of the issuing institutions.
We propose that in order to meet the financial viability requirements, gas service providers be required to post a deposit or financial guarantee bond with the Commission. The financial guarantee bond may be either a performance or payment bond.
Most parties recommend that we adopt deposit levels consistent with those in the electric service provider program.  There, the amount of the deposit increases relative to the number of customers served.  The minimum deposit for a gas service provider would be $25,000, and would increase to a maximum of $100,000.
1-250 customers 		$ 25,000
251-500 customers 		$ 50,000
501-1000 customers 		$ 75,000
1001+ customers		$100,000
Consistent with our current deposit rules, any interest earned on a cash deposit will be paid annually to the provider.
(b)	Experience of Key Personnel
The technical and operational standards proposed by the Energy Division would require a gas service provider to provide the names and titles of its key technical and operational personnel, including a description of each person’s relevant experience in the energy industry.  If outside entities are providing metering or after-metering services, the same information must be provided for its key personnel.  The report clarifies that although this information may be required for registration, awarding a registration number would not certify that a firm was competent to provide these services.
The requirement for a description of the key personnel involved in the technical and operational aspects of the applicant’s business, including relevant experience in the energy industry, provides us with critical information about the capabilities of the provider.  At least one party, NorAm, proposes limiting this requirement to executive personnel, stating that large gas service providers have hundreds of personnel involved with gas marketing, transportation, and billing operations.  We have no objection to this proposal, if it provides sufficient detail about the personnel responsible for commodity sales, procurement, metering and billing services at the operational level.
(c)	General Capability Standards
SDG&E and SoCalGas recommend compliance standards clarifying the consequences of poor performance.  SDG&E cites specific examples gleaned from its experience working with competitive electric providers.  SDG&E contends that utility distribution companies are placed in an “all or nothing” situation to deal with poor billing and collection performance by electric service providers.  If such a firm is not performing, the utility may sever its right to provide service in the utility’s territory, but SDG&E argues that it could be perceived as taking such action in pursuit of its own self interest.
SDG&E/SoCalGas propose that competing firms not be allowed to register unless they have telephone numbers through which customers could talk to their personnel the regular business day.  The Commission would set a maximum limit on the amount of time a firm’s customers must wait for their call to be answered.  The two utilities contend that such standards are needed because many of the registered electric providers have had their telephones disconnected or answered by a machine during business hours.
Edison proposes that the technical and operational standards ensure a firm’s ability to obtain and communicate usage data, communicate with the local distribution company, and handle customer complaints.  Edison recommends that the Commission require competing firms to obtain a signed service agreement with the utility prior to registering with the Commission, and to demonstrate technical and operational capabilities prior to signing a service agreement.
Enron objects to the requirement that a gas service provider obtain a service agreement with a Scheduling Coordinator.  Enron states that it opposes a “gas ISO,” and objects to any attempts to centralize or regulate the gas commodity market or transmission system.
NorAm agrees with Enron that the Commission should eliminate the registration requirement that a gas service provider obtain a signed agreement with a Scheduling Coordinator, noting that the scheduling coordinator process discussed in the DSP Report has not been well received.
Most of the general capability issues raised by parties concern business interactions between local distribution companies and gas service provider.  In today’s decision, we are proposing minimum technical and operational standards related to the registration of providers.  We intend these standards to screen out providers found to be technically deficient or incapable of providing commodity service.  As we explore additional market-oriented policies for the gas industry, we can consider more comprehensive market rules related to the interactions between local distribution companies and other market participants.
However, as SDG&E and SoCalGas note, consumers must be able to contact gas service providers by telephone for billing, service or other inquiries.  In order to acquire and maintain active registration status, we would require such firms to have working telephone service, and be available to answer consumer telephone calls during regular business hours.
b)	Denial, Suspension and Revocation
Many parties urge that we specify the consequences of a firm’s failure to meet prescribed standards through clearly defined denial, revocation and suspension procedures.
NorAm contends that we should be required to conduct a hearing prior to suspending any gas service provider’s registration to allow the firm to exercise its due process right to defend charges made against it.  NorAm states that any consumer protection rules should delineate the specific implications of suspension.  NorAm further contends that a suspended firm should not permanently lose its right to do business in the state, but should be permitted to first address and correct causes of suspension and then petition for reinstatement.
Small Business believes that the Commission should have the authority to suspend or revoke a provider’s registration without a hearing, and should in all cases have the power to suspend or revoke registration in a timely manner.  Small Business recommends that we should develop an expeditious process for suspending or revoking registration of gas service providers who fail to respond to Commission audits.
SDG&E/SoCalGas urge that we adopt a specific minimum time period before any applicant can re-register following suspension or revocation, and to permanently prevent registration in sufficiently egregious situations.  SDG&E/SoCalGas contend that individual persons found to have committed serious rule violations should be prohibited from being employed or from owning an interest in another gas service provider, and recommend that we set up a process to inform consumers if a firm is found to have engaged in improper actions, or poses a threat to consumers.
PG&E/Greenlining/Latino Issues Forum recommend that we delineate, in advance, the consequences of not meeting adopted standards.  These parties suggest that severity of the consequences be appropriate to the violation.  As an example, a firm’s failure to provide fingerprints of a new principal officer in a timely basis should be handled differently from a fraud conviction.  Parties recommend that we address what action utilities should take when a provider’s registration is suspended.
We agree that consequences should be consistent with the severity of a violation, and that all parties must understand the consequences and implications for violating either our rules or other applicable laws or statutes.  Further, our process for denial, suspension and revocation of gas service provider’s registration should be consistent with the process for electric service providers, and should follow existing Commission practices and procedures.
Again, without enabling legislation, our action to deny, suspend or revoke a provider’s registration could have very little impact on the firm’s ability to provide gas service to small consumers.
(1)	Denial of Registration
We should reject a firm’s request for registration when the firm fails to provide the information requested on the registration form, including the required documentation, such as the written customer disclosure notice.  Intentional submission of false or inaccurate information, or the felony convictions of the applicant, entity or entity’s principal officers or directors would also constitute grounds for a denial of registration.
Pursuant to our proposal, the Commission’s Executive Director, after consultation with the Assigned Commissioners, would notify an applicant in writing of the finding to deny registration.  The applicant would be notified of the scheduling of an expedited hearing, which would be held within 30 days of the notification.  The Commission would issue a decision regarding the registration status within 45 days of the expedited hearing.
(2)	Suspension and Revocation of Registration
We would have several procedural tracks available to suspend or revoke a provider’s registration.  One criterion for selecting the appropriate process would relate to the severity of the provider’s action.
The least severe process to suspend a provider’s registration is the administrative action of ministerial suspension, which would be initiated and carried out by the Director of the Energy Division.  A firm would be subject to ministerial suspension if it failed to provide the Commission with an updated application, a revised customer disclosure notice, standard service plan, or notification of any other changes to its registration information.  Ministerial suspension also applies to firms found to be in violation of the Commission’s registration requirements, including the standards for financial viability, as well as technical and operational ability.
The Energy Division would first inform a gas service provider of the possibility of ministerial suspension through a “Notice of Impending Suspension for Failure to Submit Required Information.”  The notice would advise the firm of the information required, and state that if the firm does not submit the required information to the Commission within 15 days of the notification, its registration will be suspended and its customers will be served by the local distribution company until the customers select another provider.  If the required information is not received by the Commission within the allotted 15 day period, the Commission would send a “Notice of Suspension of Registration” to the gas service provider.  The second notice would advise the company that it must cease serving its customers within 48 hours.  The notice would also advise the provider that its registration may be reinstated upon providing the Commission with the required information.
A second track allows us, on our own motion, to open an investigation into the activities of a provider that we suspect of committing fraudulent acts upon consumers.  This process may be used in conjunction with other suspension/revocation procedures.
A third procedure, similar to the procedure to deny registration, was developed to facilitate the suspension or revocation of electric service providers.  The Commission’s Executive Director, upon the recommendation of the Director of Consumer Services Division, and in consultation with the coordinating Commissioner for consumer protection, would notify a provider in writing, of the finding of suspension or revocation, and of an expedited hearing.  The Executive Director will be responsible for filing a notice with the Docket Office to open a docket.
In most cases, a gas service provider notified of impending suspension or revocation proceedings would remain in operation and could continue to solicit and serve customers.  However, in cases of extreme market abuse, or where consumer or public safety is at stake, we may issue a notice of temporary suspension, which would be followed by an expedited hearing as soon as possible, but in all cases within 30 days of the Executive Director’s notification. At the expedited hearing, a provider could request that the Commission lift the temporary suspension.
A provider whose registration has been revoked could request reinstatement by filing a formal application with the Docket Office, which would be docketed as a formal application proceeding.
c)	Written Notice and Contracts
The Energy Division recommends that we adopt a requirement for gas services providers to provide potential customers with a written notice of price, terms and conditions.  Staff contends that a written notice discloses the nature of a gas services provider’s service offering and educates consumers about the gas services providers and its product or service, and proposes inclusion of the following items:
1.	The gas services provider’s registration number, which clearly identifies the Commission as the registering entity.  This will assist consumers with knowing where to turn if they have concerns about the provider.
2.	Name, telephone number, and address of gas services providers
3.	An explanation of recurring and non-recurring charges. The price of gas should be presented in cents per therm, to allow for easy comparison. An estimate of a monthly bill at varying consumption levels should be also provided
4.	Amount of deposit, if required. The maximum allowable deposit should not exceed twice the customer’s estimated average monthly bill
5.	Length of customer’s contract or service agreement, along with disclosure of any applicable charges for early termination of contract
6.	An explanation of the billing option provided: gas services providers or local distribution company consolidated or dual billing
Additionally, staff  recommends that gas services providers be required to provide a written service contract to customers.  Any subsequent changes to the contract, including contract extensions, should also be provided in writing.  The Energy Division states that a written contract or agreement between the customer and a gas services providers protects the customer against an unauthorized change in terms, and is helpful in resolving disputes regarding the price, terms or conditions of the agreement.  Several parties propose that the definition of written notice be expanded to include electronic communication.
Enron opposes adoption of a written contract as an obstacle to quickly signing up customers verbally, telephonically or electronically.  Enron states that customers are disinclined to take the time to sign a written contract.  Enron cites D. 98-02-108 where Commission eliminated the requirement that a core aggregation customer provide its utility with written authorization to switch procurement providers, and recognized that “a prohibition on electronic or telephonic service orders is unreasonable in an age where customers are buying all manner of commodities using these media.”
Edison notes that the Commission does not require electric service providers to provide a written contract, and would need to seek legislative authority to impose this condition.  Edison further observes that such a requirement could be difficult for the Commission to enforce.
NorAm recommends that the proposed requirement of providing a customer notice should be waived for gas services providers choosing to incorporate the notice requirements into their contracts.  A clearly written contract would specify all relevant and applicable terms, including price.  Written disclosure should be required only if the gas services provider does not provide written contracts.  The gas services providers should be required to post prices in either written notice or the contract (if mandated) but not both.  NorAm observes that rather than a confusing explanation describing local distribution company/gas services providers consolidated billing, the gas services providers should provide a clear and concise statement as to how customer will be billed.
Green Mountain supports the requirement of a written notice of price, terms and conditions, with modifications to the proposed format.  Green Mountain proposes that the price be presented on the notice exactly as it will be calculated on the bill, whether by cents per therm, flat fees, or any other pricing arrangement.  Green Mountain contends that providing estimates of varying levels of consumption accomplishes the goal of providing consumers with an easy comparison.
Green Mountain opposes mandating both a written notice of price, terms and conditions and a written service agreement, contending that one document disclosing all rights, obligations, pricing, terms and conditions provides sufficient information to consumers.  Green Mountain further objects to a requirement for a written contract or agreement signed by the customer and the gas services providers, stating that this requirement is duplicative of the protections provided by independent third party verification.
Small Business concurs with the Energy Division’s view that a written notice of price, terms and conditions should not be a substitute for a written service agreement.  PG&E, Greenlining, and Latino Issues Forum observe that the written notice of price, terms and conditions should be provided in the same language used to negotiate the transaction.  TURN deems a written disclosure notice to be essential, and appears to be supportive of a final written service agreement.  TURN observes that if an entity provides several bundled services, the written disclosure and service agreement should disclose and itemize the cost of all separate services.
We see some merit in the arguments put forth to mandate both a written disclosure notice and a written contract.  We believe that reliable companies want to have good communication with their customers, and will support policies which promote customer understanding of the terms and conditions of its service offering.  We do not believe that a written contract requirement would be difficult to enforce, and recognize its value in resolving contract disputes, particularly those involving a change in terms or length of obligation.  The proposed third party verification procedures apply to customers selecting a new provider, and do not address verification of agreement to contract modifications.
We acknowledge parties’ concerns that two disclosure documents could be duplicative and an obstacle to signing up customers quickly, and therefore decline to mandate a written contract at this time.  An acceptable alternative to requiring both documents is to require gas services providers to maintain records of the price, terms and conditions notification and any subsequent notification to individual customers modifying the price, terms and conditions of the service agreement.  This alternative accomplishes the goal of providing meaningful consumer protection through proof of full disclosure by gas services providers and enhances the Commission’s complaint resolution process by ensuring ready access to a gas services providers records.
We note that this proposed requirement for gas services providers to maintain records of supplying written notice of price, terms and conditions to individual customers is consistent with the requirement recently adopted for electric service providers.  We reaffirm this enhancement to the consumer protection rules set forth for electric service providers, and believe that market participants in the gas industry will also benefit from this record-keeping process.
We agree with PG&E, Greenlining, and Latino Issues Forum that gas services providers that market to customers in a language other than English should provide the written disclosure notice of price, terms, and conditions in the same language.
Consistent with disclosure notice requirements for electric customers, we also intend that the disclosure notice inform consumers of their ability to rescind any service agreement within three days of signing up with a provider.
d)	Customer Deposit
The Energy Division proposes a maximum deposit of twice the customer’s estimated average monthly bill.  Parties point out the inconsistency with rules governing deposits for electric service providers, noting that the maximum deposit allowable for electric service providers is three times the estimated average monthly bill.
There is an inconsistency in the deposit rules for gas and electric utilities and for competitive providers.  Electric and gas utilities are allowed to request twice the average estimate monthly bill from new customers, and twice the maximum monthly bill for existing customers demonstrating poor payment habits.
Consistent with the legislated deposit requirements for electric service providers, we recommend that the written disclosure notice to allow the gas services providers to collect a maximum deposit of three times the customer’s estimate average monthly bill.
e)	Standard Bill Format
Staff proposes adoption of a standard bill format for gas services providers and utilities to assist consumers in locating required information.  Such information includes the per unit and total commodity price, itemization of other services, if applicable, the telephone number and address of the gas services providers or billing agent for consumer inquiries, a description of how consumers may file a complaint with the Commission, payment due date, and a breakdown of other billing components, including late payment charges, if applicable.
SDG&E and SoCalGas support inclusion of a basic level of information on gas services providers’ bills, and recommend that we should allow single consolidated bill format for a gas services providers and electric service provider providing both services.
Enron opposes both a precise bill format and a precise price unit of measurement, but supports the other proposed bill requirements: clear description of price and any and all other services, and a contact telephone number.
Green Mountain supports adoption of standard information to be included on each bill, but proposes that the gas services providers be allowed to develop the actual bill format.  Green Mountain recommends the inclusion of specific items on each gas services providers bill: account number, billing period, amount due, due date, usage in therms during billing period, phone number for billing inquiries, description of how to pay the bill with options (if any), description of penalties for past due bills, description of complaint procedures, including how to contact the Commission, and itemization of charges into bundled components if the entity is performing consolidated billing.
Small Business supports a standard bill format for all providers and recommends that we adopt many of the reforms proposed by Federal Communications Commission in its Truth-in-Billing Notice.  NorAm questions who will participate in the bill development process and its necessity.
Edison opposes the standardized billing format as costly to implement and of little benefit to consumers.  SDG&E/SoCalGas also oppose the standard bill format if it means existing bill format would have to be changed, citing expense issues.  SDG&E/SoCalGas would support a requirement for basic level of information on bills.  The two utilities assert that an identical format for all providers might be unnecessary barrier to entry for gas services providers and could increase costs to gas local distribution company customers.  These parties further note that the consumer information requirements imposed on local distribution companies should similarly apply to gas services providers, which include information on bills, disputed bill resolution, ability to impound disputed amount with the Commission, mandated notices to customers.
PG&E, Greenlining, and Latino Issues Forum observe that if a standard bill format is adopted, all parties will need sufficient lead time to implement the new requirements.
The customer bill is probably the most widely-read source of information about the prices, products and services ordered and used by consumers.  The information appearing on the bill should be useful, relevant, and answer many of the consumer’s billing and service questions.  The bill should clearly indicate the commodity price and consumption level, an explanation of the charges, how the provider may be contacted, and the recourse available to dissatisfied customers.  The precise format of the bill is less important than the quality and consistency of information provided.
We note that ongoing policy discussions about the scope and implementation of gas industry changes could add to the bill’s informational requirements.  However, it is possible to adopt the framework for the standard bill requirements.
Required elements of a bill provided by both utilities and gas services providers should include:
•	The customer’s name
•	Account number(s)
•	Meter number
•	Billing period
•	Current and prior meter reads
•	Commodity usage
•	Description and itemization of charges for other services, including unbundled services for consolidated billing, taxes, fees or other charges
•	Payment due date and how to pay
•	Late payment charges
•	Billing options, if applicable
•	Deposit requirement
•	Complaint procedures for both the billing entity and the Commission including information on how to contact the Commission
•	A telephone number and descriptor, indicating that the customer may call for inquiries or complaints. gas services providers and LDCs providing consolidated billing should provide the telephone numbers of both entities, and should also provide these numbers upon the customer’s written or verbal request
The utilities and gas services providers may add additional line items that will better assist consumers with understanding their charges, services, rights and recourse.
f)	Standard Service Plan Filing
Although the Energy Division report did not discuss submittal of a standard service plan by each registered gas services providers, submittal of such a plan is consistent with our requirements of electric service providers.  We believe this requirement has merit, and should be included in the registration package, along with a gas services provider’s written notice of price, terms and conditions.  Such a plan should include the number of customers served, the terms and conditions of the standard or basic service plan(s) offered by the gas services providers, and any marketing or advertising materials provided to customers via hard copy or through electronic means.
Filing of a standard service plan serves several purposes.  It helps to ensure that gas services providers are meeting our disclosure requirements with respect to price, terms and conditions, and provides us with useful market information, such as pricing and number of customers served.
If this requirement is adopted, the standard service plan(s) should be filed with the Energy Division biannually.
g)	Third Party Verification
The Energy Division observes that independent third party verification is mandated for the competitive electric and telecommunications industries and for the current core gas aggregation program, and is an effective deterrent to “slamming,” or unauthorized switching of provider.  Staff cites examples of switching methods used by unscrupulous providers, such as forged authorizations and “sweepstakes” schemes, where a customer signing a document to enter a contest has unknowingly authorized a change in provider.
SDG&E and SoCalGas recommend that we require gas services providers to pay the local distribution company’s a cost-based handling penalty when gas services providers switch customers without authorization.  The joint parties question who is responsible for third party verification and how long must transaction confirmations be retained.
Enron contends that we cannot impose a third party verification requirement without legislation, but supports the adoption of third party verification standards for small gas customers.  Enron recommends that four options be available for both residential and small commercial customers: 1) independent third party  telephone verification; 2) return of written post-transaction confirmation from customer; 3) written agreement for service; 4) electronic confirmation, including computer communications.  Enron asserts that the more restrictive provisions of Pub. Util. Code Section 366.5(b) for electric residential customers have made market entry and customer acquisition more expensive.
ORA supports mandatory third party verification for gas services providers serving residential and small commercial customers, and recommends that gas services providers be required to submit a copy of an agreement with a verification company as part of its registration.
We note that mandatory third party verification of a change in electric provider for residential and small commercial customers was an element of Assembly Bill 1890.  This legislation was enacted to prevent the occurrence of unauthorized switching of a customer’s electric service provider.  Similar legislation would provide us with the authority to enact and enforce verification procedures for gas services providers.  We propose that gas services providers should be held responsible for providing independent third party verification to confirm a residential consumer’s intent to change providers. The gas services providers should ensure that a customer’s oral confirmation will be recorded and maintained by the third party verification company, and that the confirmation will be available to the consumer upon request.
In the absence of a signed agreement, the date of independent verification becomes a substitute for the day an agreement is signed.  This date becomes Day 1 of the customer’s three-day “right to rescind” period.  A consumer may cancel a contract or agreement by notifying the gas services providers in writing by midnight of the third business day after 1) a contract is signed, or 2) the change of provider is independently verified.
h)	Confidentiality of Information
The staff report urges that we to establish a balance between customer privacy and the market participants’ need for information.  The report proposes that customer-specific information, such as billing, usage or credit data, be considered confidential, to be released to registered gas services providers only upon written authorization.  Non-specific usage or load information could be released to gas services providers in aggregate form.
ORA proposes that under a voluntary registration program, confidential customer information be released only to registered gas services providers, and not to gas services providers who do not volunteer to register.
Customer-specific information may be defined as the usage data, or usage history, of a specific customer.  Consistent with existing customer confidentiality requirements for electric service providers, a customer’s written consent authorizing release of account information by a local distribution company to a registered gas services providers must be obtained by the gas services providers prior to release of customer-specific information.  This transmittal of information will include 12 months of customer usage history, which may be requested by the gas services providers up to two times per year at no cost to the gas services providers.
Customer-specific information compiled into a matrix or database without customer identities may be requested by a registered gas services providers without written customer authorization.
i)	Complaint Resolution
The Proposed Consumer Protection Program Report recommends that we be given explicit authority to investigate and adjudicate complaints against both registered and nonregistered gas services providers marketing gas service to residential and small commercial customers.  Without this authority, the only recourse available to small consumers seeking dispute resolution may be to file an action through the court system.  Staff points out that the lack of Commission authority will not prevent consumers from seeking our assistance, but would hinder our ability to undertake consumer protection activities.
Staff indicates that consumer complaints may require various types of resolution processes.  Many complaints may be resolved on an informal basis through the Commission’s Consumer Affairs Branch; more complex complaints may necessitate alternative dispute resolution or a formal complaint filing.
The Energy Division report outlines the types of complaints consumers could expect the Commission to resolve: billing disputes, reasonableness of a gas services provider’s terms and conditions, noncompliance with a law, Commission decision, or rule related to the competitive gas industry, and allegations of unfair or illegal marketing practices.  Examples are cited of areas where we should be given the authority to resolve billing complaints related to charges for gas not used or delivered, or at a price not agreed upon, disputes over the service agreement, such as deposit amount, length of service contract or other terms of the agreement, and consumers unfairly targeted by unscrupulous marketers or sold service at unreasonable prices.
Most parties filing comments agree that we should have some level of authority to resolve consumer complaints against gas services providers.  Parties differ on the types of complaints we should seek to resolve.
NorAm proposes that customers should be required to demonstrate that they first attempted to resolve dispute with their gas services providers before filing a complaint with the Commission.  If the amount in dispute is less than $5000, the Commission should make optional, binding arbitration by a neutral third party available to the complainant, as opposed to a lengthy Commission proceeding.  NorAm notes that $5000 is jurisdictional limit for suits filed in Small Claims Court, and enables customers to pursue another course of action than a Commission-imposed remedy.
NorAm argues that it is inappropriate for the Commission to rule on the reasonableness of an unregulated marketer’s terms and conditions, and proposes an alternative for customers with a written contract.  If the contract contains the disclosures specified in the written notice requirement, as well as the customer’s right of rescission, and a gas service provider is in compliance with the above criteria, the Commission should not be permitted to examine reasonableness of terms and conditions of service.
Although it agrees with the Energy Division’s discussion of the complaint resolution process, Green Mountain believes we should have no regulatory oversight of pricing.
Edison recommends that we seek legislation to ensure its ability to investigate and resolve complaints symmetrically to both gas and electric providers.  Edison notes that D. 98-03-072 requires the electric utilities to monitor and report consumer complaints about electric service providers to the Commission, and recommends that a tracking and reporting system be incorporated into our natural gas consumer protection program.  This system should have similar reporting requirements that are clearly defined.  Edison contends that the local distribution company should not be put in the role of policing the behavior of gas services providers.
SDG&E, SoCalGas, and Small Business recommend that we compile and publish a list of complaints resolved adversely against registered gas services providers.
PG&E, Greenlining, and Latino Issues Forum observe that our complaint process can appear intimidating to vulnerable communities, low-income customers and those with limited language skills.  The joint parties recommend that we make our complaint process as accessible as possible.  Suggested enhancements include increased language capability and expanded hours.
Small Business provides similar suggestions for improvement to our public intake and complaint process, adding that complaint staff should have an understanding of the problems experienced by small business customers and should resolve problems quickly and fairly.
In D. 98-08-030, we recognized that lifting the core aggregation program limits could have the effect of increasing the number of competitive choices available to residential and small commercial customers.  Removing these limits should not have the unintended consequence of reducing the avenues available for consumers to seek redress for problems, inquiries or complaints. Consumers unsatisfied with attempts to resolve complaints with their service provider should have access to a convenient, neutral complaint resolution forum.
We propose to make available a venue for consumer complaints regarding billing, including disputes over the deposit amount, price, charge, terms and conditions of service, as well as deceptive or abusive marketing practices.  If approved, we further expect to provide an array of complaint resolution services, including an informal complaint process, alternative dispute resolution, and mediation.  We believe consumers should have the option of filing a formal complaint here as an alternative to pursuing legal remedy through the court system.
We believe this authority should be extended to include review of the reasonableness of a gas services provider’s terms and conditions.  This review does not imply a “reasonableness review” in the traditional context of rate regulation; rather, it extends broad authority to the Commission to investigate suspected trends of customer abuse.
Customers disputing bills from energy utilities or electric service providers are allowed to impound the amount in dispute with the Commission to avoid termination of service.  This procedure should also be made available to consumers disputing bills from gas services providers.
The Energy Division recommends that we should have the authority to investigate and adjudicate complaints against registered and nonregistered providers marketing to residential and small commercial customers.  We emphasize that under our proposal, all providers intending to serve residential and small commercial customers would be required to register with the Commission, but recognize that unscrupulous providers may not do so.  Just as consumer protections apply to all small consumers, enforcement of market rules must apply to all providers marketing to small consumers, registered or not.
j)	Consumer Education
We recognize and acknowledge the importance of informing consumers about any changes to the natural gas industry, the choices available to them, and their rights and recourse.  In order to feel confident in making decisions among competitive products and services, consumers must be provided with sufficient information about their available options and how to protect themselves from abusive practices.  The Energy Division report observes that as we develop and enhance our consumer protection role, the we must also accept the responsibility of providing consumers with information about the industries we oversee.  Staff contends that as the policy expert and public agency, we are in a unique position to provide accurate, unbiased information to consumers.
The Energy Division recommends four key messages to be communicated as part of a program to educate consumers about the competitive gas industry.  These messages were identified through consumer research conducted for the Electric Restructuring Consumer Education Program as areas where consumers wanted to receive information.
1.	Safety and Reliability
2.	Pricing - rates, billing
3.	Making an informed choice
4.	Consumer Protection - Who’s in charge? Where do I go for help if something goes wrong?
Approaches used in prior Commission-sponsored customer education programs (Caller ID, Electric Restructuring) to deliver key messages about industry changes include mass media such as television, radio, printed advertisements), direct mail, bill inserts, a toll-free call center, web site, multi-lingual printed materials to meet the needs of all consumers, media relations and community outreach.  Staff recommends a combination of approaches to educate consumers about changes to the gas industry.
Most parties recognize the need to educate consumers about gas industry changes, but offer varying opinions on issues of size, scope, content and funding of an education program.
Enron supports a customer education program through which the Commission advises customers of new structural changes to the market, but opposes a program designed to characterize markets’ products, services or prices.  Enron concurs with program messages urging customers to ask for and understand pricing information prior to agreeing to service.
ORA contends that since the competitive natural gas market is developing slowly, so too should consumer education.  The Commission should learn from electric industry restructuring, where small consumers have been slow to switch to competitive providers.  ORA asserts that spending money to tell customers they can choose competitive provider when there are few competitors serving that market is inefficient and wasteful.
ORA supports renaming the Electric Education Call Center the Energy Education Call Center.  ORA believes the Commission should publicize the Call Center via prominent utility bill inserts prompting customers to call for information on competitive gas and electric markets.  A list of registered gas services providers could be distributed by bill insert, the Call Center and the Commission website.
ORA contends that the Commission should place emphasis on historically vulnerable segments of population: low-income, limited and non-English speaking.  ORA also believes that mass media blitzes should be avoided in favor of grass roots efforts by community-based organizations (CBOs).  ORA recommends that the Commission should pursue development of a network of Regional Energy Offices throughout the state to accomplish the multiple objectives of consumer education, energy efficiency and low income energy assistance.
Edison proposes that the Commission use the same framework of the electric restructuring customer education program for a natural gas program.
In joint comments filed by SDG&E and SoCalGas, the utilities assert that consumers must be educated about roles and responsibilities of gas services providers and local distribution companies with respect to unbundled safety-related services so they know whom to contact in safety-related situations.  SDG&E/SoCalGas oppose a natural gas education program similar in scope and size to the electric program.  The utilities further recommend that the Commission ensure adequate time is allowed for up-front research and planning to target communications, and to allow reasonable production lead-time.
PG&E/Greenlining/Latino Issues Forum recommend that the customer education program be developed after the Commission and Legislature resolve policy issues associated with gas restructuring.  Depending on any policy changes, the Commission’s resources may be better expended through grass roots and CBO efforts.  The parties recommend that educational materials should be designed to provide information to non-English speaking as well as low-income customers.
Small Business agrees with the staff report that consumers need reliable information regarding safety and reliability, pricing, making an informed choice, and where to go for help if something goes wrong.  Small Business recommends that the Commission develop special collateral materials for small business and pursue outreach to small business through trade organizations and chambers of commerce.
Several parties made recommendations about the funding of a natural gas customer education program, and appropriate levels of expenditure.
NorAm contends that gas services providers should not be responsible for funding the program, stating that such an obligation would create barriers to entry and deter customers from choosing a gas services providers.  NorAm proposes that the local distribution companies should fund the education program and recover costs from all gas consumers, not just those who opt for gas services providers service.  NorAm points out that the Commission approved this funding mechanism for the electric restructuring customer education program.
SDG&E, SoCalGas, and ORA oppose funding a natural gas education program at the level of the electric restructuring program.  SDG&E/SoCalGas point out that the natural gas industry has already been substantially restructured over the past ten years, resulting in gas programs that are well-established, whereas direct access to competitive electricity was essentially new for all end-use customers.  SDG&E/SoCalGas urge the Commission to conduct a cost/benefit analysis to ensure that only levels of spending demonstrated to have net benefits for consumers should be authorized.  These utilities further recommend that specific goals for a gas customer education program, including levels of consumer awareness, should not be set without a cost/benefit analysis.  ORA contends that spending money to tell consumers that they can choose a competitive provider when there are few competitors serving that market is inefficient and wasteful.  PG&E/Greenlining, Latino Issues Forum assert that the education program should be cost effective, designed to match resolved policy issues.
We agree with parties that a natural gas customer education program with the size and scope of the electric restructuring education program is unnecessary.  It is crucial, however, that consumers understand that similar changes are taking place in the gas industry, that they are provided with sufficient information to make informed decisions, and that they know their rights and remedies to dispute fraudulent actions or inadequate service.  We have articulated our intent to provide consumers with neutral, unbiased, useful information.  In D. 98-08-030, we stated:
“Natural gas consumers should be informed about the changes that have occurred and that are being considered in the natural gas industry so that they are better positioned to take advantage of the options available to them.  They should also be more educated and confident about their rights and recourse options in a more competitive gas industry.”
Success of any natural gas customer education program should not be measured in terms of the number of customers choosing to purchase commodity service from a non-utility provider.  Our intended goals for consumer education are to provide consumers with information that will allow them to understand the choices available to them, make informed decisions, and protect themselves from fraud and abuse.  The expansion of the competitive gas market also brings opportunities for convergence of energy service offerings, which should be added as a key message.
We agree with parties that the program should not be funded by the nonutility providers, and concur that a gas services providers-funded program could create barriers to entry and discourage customer choice.  We further agree that education costs should be recoverable from all consumers, not just those electing to take service from a non-utility provider.
We recommend that funding the natural gas customer education program at a level equal to the electric program is unnecessary.  As recommended by the Energy Division, this is a good opportunity to coordinate both gas and electric restructuring consumer education, which should serve to leverage resources and lower program costs.  We will direct CSD and the Energy Division to make further recommendations on the types of educational activities that may be reasonably undertaken.  Suggested activities could include the recommendations made by staff and ORA to expand the existing Electric Education Call Center to answer questions and provide written materials about gas industry changes in multiple languages, a Commission-prepared bill insert, a natural gas web page with useful consumer information, including a list of providers, a media kit, and an outreach program.
k)	Rate Comparison-Pricing Database
The Energy Division states that consumer research conducted to evaluate the effectiveness of the Electric Restructuring Customer Education Program indicates that consumers are seeking specific information about competitive providers, including an unbiased comparison of rates, services and other features.  Staff recommends that the Commission seek input from parties on how a “pricing database,” providing consumers with real-time information, could be created and maintained.
ORA supports development of an informational database, pointing out that with gas prices established on a monthly basis, data collection and dissemination would be a manageable task.  ORA suggests modifying the concept to create a database of current service offerings, rather than  a real-time pricing database.  ORA recommends that we direct the Energy Division or ORA to establish and maintain database on the CPUC website, noting that ORA has current responsibility for providing pricing and service information to consumers on electric service providers.  TURN and Small Business also support the concept of a pricing database. 
NorAm expresses concerns with confidentiality and release of competitive information, recommending that gas service providers participation should be optional, not mandatory.  NorAm contends that any pricing database should not be considered in the consumer protection part of the proceeding, but should be raised in a much broader context in the general proceeding.
SDG&E and SoCalGas take a skeptical view, arguing that a pricing database takes the limited view of the scope of gas services providers’ offerings: that of price only.  These utilities believe that the majority of core aggregation transportation customers are not in the program just for lowest price benefit, but for value-added services, such as a single bill for statewide facilities, personalized billing analysis, and special pricing arrangements such as guaranteed fixed prices or market capped price.  The joint parties contend that a Commission-published list involves too much regulatory intervention into the competitive marketplace.  Consumers wanting real-time pricing information should pay the cost of providing it; associated costs should not be bundled in regulated gas service or in access to purchasing from any gas services providers.
Enron opposes creation of a pricing database or any other program characterizing a marketer’s products, services or prices.  Enron contends that government should not attempt to advertise or disclose price terms on the grounds that such disclosure would severely distort pricing of the gas commodity.  Enron further contends that the Legislature has indicated that it does not support Commission efforts to publicize prices.
We believe the concept of an informational database is consistent with our responsibilities to collect and disseminate meaningful information and to provide useful shopping tools to consumers.  In D. 98-03-072, we carried out the Legislature’s mandate to provide this type of consumer service. Pub. Util. Code Section 392.1 required that we direct ORA to collect and analyze the standard service offerings filed by registered electric service providers “for purposes of preparing easily understandable informational guides or other tools to help residential and small commercial customers understand how to evaluate competing electric options.”
It is unclear how the informational database jeopardizes the confidentiality of gas services providers through release of competitive information.  Gas service providers are expected to keep track of the pricing structures and service offerings of their competitors as a necessary part of doing business.  Consumers, on the other hand, could have difficulty obtaining this type of information.
If we are given the authority, we would direct ORA, in conjunction with the Energy Division, to create a tool to assist consumers with comparing the service offerings of gas services providers.  We recognize that price may be only one of several factors that consumers consider when shopping for natural gas.  ORA should incorporate any other types of services included in a gas services provider’s standard service plan filing.  The completed product should be posted on the ORA web site, and ORA should coordinate with CSD to explore other methods of dissemination.
3.	Conclusions Concerning Consumer Protections
Improved consumer protections are needed now, even before we have a complete picture of what the natural gas industry will look like.  Core aggregators are looking to expand offerings to individual residential and small commercial customers in the near-term.  At such a time as the core gas aggregation program limits are lifted, providers will not be inclined to wait for enactment of consumer protection rules prior to offering competitive commodity service.  We encourage the Legislature to act in this session to grant us the authority to implement the proposals discussed in this order.  With such changes in place, we feel it would be appropriate to lift the limits on the core aggregation transportation programs.  The proposed rules, as revised in response to comments, are attached as Appendix B to this order.
J.	Statewide Consistency Assessment
At our request, many parties worked diligently on the creation of a remarkable inventory of natural gas program elements throughout this state.  The inventory highlights inconsistencies in the programs administered by PG&E and SoCalGas.  In many instances, the document also states the opinions of various participants as to whether or not the inconsistencies should be eliminated.  However, it does not explain why consistency is important.
Many inconsistencies would be eliminated if the other changes discussed in this order were to occur.  In addition, we will call for additional workshops at which we would hope the participants could identify any specific problems caused by inconsistent rules or services or any Commission policies that would be furthered if we were to adopt a more consistent approach.
IV.	Conclusion
We expect to issue two reports to the Legislature as a result of our investigation of the California natural gas industry.  First, consistent with the earlier discussion in this decision on consumer protections, we plan in the very near term to submit a report to the Legislature offering our proposal for expanding the protections for core natural gas customers and seeking legislative procedural guidance.
Second, in his December 21, 1998 ruling, President Bilas outlined a procedural proposal for drafting a report to the Legislature with our recommendations for structural change to the natural gas industry.  We concur that the next phase of this inquiry should consist of hearings on a broad range of benefit and cost issues related to the most promising market structure options contained in this decision.  We will open a new docket in which to consider this input.  The benefits and costs that may be addressed, at this point include, but are not necessarily limited to, service and reliability, labor impacts, consumer protection impacts, effects on the environment and safety implications of the specific change options identified herein.  If appropriate, concurrent with the cost-benefit process, we intend to convene Open Comment Meetings to better understand public reaction to the identified most promising options.
Thereafter, we intend to release for comment a draft report to the Legislature on market structure issues.  That draft will be followed by the issuance of a final report to the Legislature.
We expect this decision to result in two additional outcomes.  First, we expect PG&E and SoCalGas to work with their customers to arrive at a mutually acceptable means of communicating the market and operational information necessary for utility customers to function confidently, effectively and efficiently in the natural gas marketplace.  If parties are unable to agree to information disclosure standards by July 15, 1999, we will include the information issue in those to be resolved in the cost-benefit phase of this proceeding.  Second, we expect SoCalGas to file an advice letter within 90 days of the date of this decision containing proposed tariffs that clarify its current windowing practices.
At the March 23, 1999 oral argument a number of parties suggested that resolving the contested issues of this case via settlement might be an attractive procedural option.  Many of the parties expressing this view noted, however, that in order to proceed with settlement discussions it would be helpful for us to first provide an indication of our thinking about the policies and structure that should apply to the California natural gas industry.  We have done so in some detail in this order.  If parties still believe that resolving the contested issues of this case via settlement would prove to be beneficial, we encourage them to pursue this option.  Any proposed settlement should be consistent with Rules 51 et seq. of our Rules of Practice and Procedure.  The proposed settlement should be submitted in the new docket
It is critical that any such agreement reflect an appropriate balance of the interests of all stakeholders affected by the outcome in this proceeding.  For this reason, no interested parties should be excluded from the negotiating process. all interested parties should have a place at the table either directly, or through a caucus representative.  Finally, to the extent feasible, we offer the Commission’s resources to assist in the negotiation process.  We can provide meeting space, notify participants, supply a facilitator or mediator, or furnish other similar assistance as needed.
We have identified a schedule to apply for the cost-benefit analysis and certain other events.  If the Commission is not advised that parties have reached settlement within 60 days of the effective date of this decision, we will proceed according to the following schedule:
Cost-benefit testimony distributed:		September 9, 1999
Cost-benefit rebuttal testimony
distributed:						September 24, 1999
Hearings on costs and benefits of 
promising options identified here:		October 11-15, 1999
Opening Briefs on costs & benefits
filed:							November 5, 1999
Reply briefs on costs & benefits 
filed:							November 19, 1999
Open Comment Meetings:			To Be Determined
Findings of Fact
1.	The creation of firm, tradable intrastate transmission rights offers the hope of improving efficiency through value-based pricing, as well as providing individual shippers with greater certainty as to their ability to move certain quantities of gas through the pipeline system.
2.	We have yet to determine that appropriate mechanism for allocating transmission capacity on the SoCalGas system.
3.	It is unlikely that the market will accurately reflect the value of transmission resources if SoCalGas were to define its marketable transmission access in a way that did not include the Hector Road facilities.
4.	The failure to provide at least window-style access through Hector Road has resulted in lost opportunities for bringing relatively inexpensive gas into Southern California.
5.	Because of the utilities’ dominant positions in the storage market, the utilities can exercise discretion in determining who should have access to storage and at what price.
6.	A utility faces the incentive to manipulate its system and the prices it charges for storage and intrastate transmission.
7.	SoCalGas is the dominant provider of gas storage in Southern California and is likely to remain so, even if Montebello is operated by another firm.
8.	In the absence of meaningful competition for gas storage in Southern California, it is not a promising option to grant SoCalGas unlimited control over prices and supply.
9.	Allowing individual shippers and customers to bid for firm storage access rights should promote more efficient use gas storage resources.
10.	The current market structure provides an incentive for the distribution companies to operate their transmission systems in a manner that encourages the use of their own storage facilities instead of those owned by competitors.
11.	Even if SoCalGas and PG&E were to divest their transmission assets they would have to contract significant amounts of capacity to meet their customers’ requirements.
12.	After divestiture of their storage assets, PG&E and SoCalGas would likely have the same incentive to protect the value of their storage assets that they have now.
13.	The divestiture of gas transmission or storage facilities by a utility and the acquisition of those facilities by another entity do not necessarily prevent market abuse.
14.	Shippers need to be better-equipped to anticipate and respond to OFOs.
15.	It is logical to assume that if PG&E had more storage capacity set aside to support its balancing efforts, it would have greater ability to smooth out fluctuations in system balance without calling OFOs or undertaking curtailments.
16.	The record before us does not demonstrate that PG&E called OFOs or SoCalGas called overnomination events in order to attract hub services customers.
17.	There is certainly a possibility that PG&E or SoCalGas could seek to take unfair advantage of its dual status as core provider and manager of its pipeline system; however, the evidence before us does not support a conclusion that either company has acted in an inappropriate manner.
18.	Improving the real-time, detailed information about a local distribution company’s balancing practices that is made available to market participants will provide greater opportunity for continuous oversight of the utility’s practices and should serve to discourage any inappropriate exercise of discretion.
19.	As long as SoCalGas’ core services are intertwined with its management of its pipeline system, it is unlikely that we can ensure that the market is free of cross-subsidies or that SoCalGas is not making decisions that enhance its shareholder interests at the expense of other customers.
20.	SoCalGas proposal to institute daily balancing does not constitute a specific plan for removing core assets from the balancing function.
21.	It would be premature to pursue a mandatory daily balancing requirement at this time.
22.	The provision of a daily balancing option may be necessary in order to implement other reforms such as the electronic trading of imbalances as well as cost and rate separation for balancing services.
23.	While a targeted OFO alone may not be enough to keep the system in balance, it may be a constructive starting point in some situations.
24.	Since a balancing tolerance is paid for by shippers as a component of their intrastate transmission rates, the plus or minus tolerance that shippers are allowed to have on a daily or monthly basis is a right that they are entitled to and that they should be allowed to trade or sell.
25.	The trading of imbalance rights would give shippers the ability to adapt to daily balancing rules, where they apply, during a given day’s nomination cycle.
26.	We find the concept of imbalance trading to hold sufficient promise to merit further inquiry.
27.	The utilities have extracted very different fees from different customers for what appear to be very similar hub service offerings.
28.	PG&E’s and SoCalGas’ ability to retain hub services revenues creates an incentive to increase opportunities to sell those services.
29.	The local distribution companies perform a valuable service for core customers, and we have seen no compelling reason to remove the local distribution companies from that service.
30.	The lifting of the core aggregation threshold and core participation cap will expand the competitive options available to residential and small commercial customers.
31.	The separation of interstate capacity costs from the unbundled rates for SoCalGas would remove an obstacle to competition.
32.	Customers and competitors need more data about the utilities’ transportation and storage services than is currently being provided.
33.	With adequate real-time data, market participants may be able to perform their own individual calculation of the likelihood of an Operational Flow Order and take any steps needed to reduce their exposure to penalties that would apply if an OFO is called.
34.	Information about storage and transmission service capacity would enable market participants to assess the availability and reliability of market center (hub) services more accurately.
35.	Knowledge about market dynamics is an important competitive tool.
36.	Customer access to real-time consumption data is consistent with our goals of increased market efficiency and providing competitive tools.
37.	Disclosure of transaction-specific details requested by parties is basic and fundamental to an efficient market.
38.	Participation in the secondary market transactions through a mandatory Electronic Bulletin Board is consistent with our goals of enhancing market efficiency, preventing anti-competitive behavior, and providing additional competitive tools to the marketplace.
39.	Providing more information is the least intrusive means of addressing some of the current concerns about potential utility anti-competitive behavior and market inefficiency.
40.	It is important that any entity competing to provide a natural gas service have access to exactly the same information about demand forecasts and the existing system conditions that is available to utility staff.
41.	We are not persuaded that disaggregating demand forecast information will create a disadvantage for any customer, including the core.
42.	There is a compelling argument for maintaining the relatively clear accountability that the natural gas distribution companies have for the safety of the gas delivery system through the distribution system to the burner tip.
43.	In D.98-08-030, the Commission observed that there is good reason to consider opening the natural gas bill rendering, remittance processing, and collections services functions (billing) so that competing gas and electric providers can choose to provide a consolidated bill for gas and electricity and so that the customers of such providers will not face duplicative charges for the billing function.
44.	As we continue the movement toward the broader offering of competitive services, it is important to ensure that all costs are assigned to the appropriate function.
45.	The offering of separate rates for competitive or optional services is critical to a customer’s ability to make an informed, efficient business decision.
46.	The consumer protection rules set forth in this opinion provide reasonable and necessary protections for residential and small business customers.
Conclusions of Law
1.	We consider the creation of a statewide system of tradable intrastate transmission rights to be worthy of closer examination in the next phase of this proceeding.
2.	SoCalGas should offer its suggestion for the best way to divide its transmission system into functional components, even if the company would rather that no changes be made.
3.	We should direct SoCalGas to file an advice letter containing proposed tariffs that clarify its current windowing practices.
4.	We should ask parties to consider the costs and benefits related to creating a market for tradable storage rights in southern California and preserving such a market in northern California beyond the period of the Gas Accord.
5.	Parties should include in their analysis of creating tradable transmission rights some discussion and analysis of the capacity allocation mechanisms available.
6.	In the next phase, we should ask PG&E to identify the incremental cost of expanding balancing services and should ask all interested parties to address the economics of this step.
7.	We should direct SoCalGas to prepare a proposal for removing core assets from the system balancing function as part of its cost/benefit analysis for the next phase of our inquiry.
8.	We should consider the costs and benefits of the daily balancing option in the next phase of this inquiry.
9.	The Commission should explore targeted OFOs along with other similar reforms in the cost-benefit phase.
10.	We should separate hub services, when possible, from the procurement function to eliminate the possibility of a conflict of interest affecting the two functions.
11.	Core load served by local distribution companies should be subject to the same imbalance penalties as any other customer, except in emergency situations.
12.	Noncore customers that are large enough to make their own purchasing needs, are able to take advantage of price opportunities, and generally do not require default service should not be allowed to make temporary use of local distribution company procurement service.
13.	We should ask the interested parties to this proceeding to use the guidelines provided today to begin working together in an effort to agree on gas market disclosure requirements and procedures.
14.	The disclosure of information should not come at the expense of the current utility department’s ability to provide low-cost, high-value services to its customers.
15.	Those customers who want or need such information should have real-time access to their consumption data in order to better manage their pipeline flows.
16.	In the absence of detailed cost information, the most promising option going forward appears to be for the utilities to make available to any customer, at the customer’s expense, the equipment, technology and training necessary for expanded customer access to timely consumption information.
17.	We should direct the utilities either to provide timely information along the lines of the specific requests outlined in this decision, or to find different ways to convey to shippers information that they need to function effectively in the marketplace without compromising confidentiality concerns.
18.	We do not currently believe that it is a promising option to encourage the cost or rate separation of meter reading or servicing,  or of what have been referred to as after-meter services.
19.	It may be appropriate for the natural gas utilities to provide billing options similar to those currently offered on the electric side.
20.	We should recommend to the Legislature that it enact legislation codifying the consumer protection measures as discussed herein.

ORDER

IT IS ORDERED that:
1.	In this decision, we have identified the most promising options for structural changes to the regulated California natural gas industry.  It is our intention to now focus our inquiry on the benefits and costs related to the adoption of the options identified in this decision.  The benefits and costs that may be addressed, at this point include, but are not necessarily limited to, service and reliability, labor impacts, consumer protection impacts, effects on the environment and safety implications of the specific change options identified herein.
2.	We encourage market participants to pursue a comprehensive settlement consistent with the promising options identified in this decision.  We set aside the next sixty days in this process for the pursuit of such a settlement.  Any proposed settlement should be submitted in the new rulemaking, opened today.
3.	We also encourage market participants to work together to develop a plan for sharing information about transactions, usage and demand forecasts as described in this decision and to submit such a plan to this Commission no later than 30 days from the effective date of this decision.
4.	In the absence of the submission of a comprehensive settlement within sixty days of the date of this decision, the following schedule applies:
Cost-benefit testimony distributed:		September 9, 1999
Cost-benefit rebuttal testimony
distributed:						September 24, 1999
Hearings on costs and benefits of 
promising options identified here:		October 11-15, 1999
Opening Briefs on costs & benefits
filed:							November 5, 1999
Reply briefs on costs & benefits 
filed:							November 19, 1999
Open Comment Meetings:			To Be Determined
5.	The respondent utilities shall distribute testimony, pursuant to the above schedule, addressing costs and benefits of each of the promising options identified in this decision and addressing all of the other questions set forth for their consideration in this decision.
6.	Any other party may distribute such testimony, pursuant to the above schedule, addressing any or all of the promising options and other questions raised in this decision.
7.	Southern California Gas Company shall submit, with its testimony, a proposal for identifying components of its transmission system and for developing a market for the sale of tradable rights to transmission and storage capacity.
8.	Southern California Gas Company shall file an advice letter within 90 days of the date of this decision containing proposed tariffs that clarify its windowing practices.
9.	The respondent utilities shall fully answer all reasonable data requests related to the preparation of cost and benefit testimony, including questions related to separate costs for various utility functions.
10.	Pursuant to Pub. Util. Code Section 328, we intend to report to the California Legislature our proposals as a result of this process.  After considering the merits of a comprehensive settlement, or after the completion of the cost-benefit analysis, we will prepare a draft report which we will circulate for comment, and then a final report, which we will submit to the Legislature.
11.	We recommend to the California Legislature that the consumer protection measures proposed by the Commission’s Energy Division, as revised in this decision, be adopted by statute at the earliest possible date.  We further recommend that the Legislature provide an exception to Senate Bill 1602 to allow this Commission to remove the current restrictions that limit participation in the utilities Core Aggregation Transportation programs.  This exception would allow the limits to be removed before January 1, 2000, but after the Commission has implemented the consumer protection measures.  Within 30 days from the effective date of this decision, the Energy Division shall prepare a report to the Legislature setting forth these recommendations.
12.	Within 90 days of the effective date of this decision, Southern California Gas Company shall file an advice letter with proposed tariffs that clarify its current windowing practices.
13.	Today, we open a new rulemaking proceeding to consider evidence related to the costs and benefits of various promising options and to prepare a report to the Legislature.  The full record of Rulemaking 98-01-011 shall be incorporated in the new proceeding.
14.	This proceeding is closed.
This order is effective today.
Dated 					, at San Francisco, California.
Appendix B
Provider Registration
Gas service providers (gas services providers) intending to provide service to residential and small commercial customers will be required to register with the Commission. Information to be provided includes: legal name(s), type of business entity; physical and mailing addresses; telephone number; majority owner or controlling entity; provider type; affiliates; customer class and geographic location to be served; a copy of an executed local distribution company service agreement; information on key technical personnel; customer notice of price, terms and conditions; disclosure of criminal conviction(s), full set of fingerprints of principal officers; and information related to other service offerings.

Screening Process for Gas Service providers
Criteria measuring a gas services provider’s demonstrated financial, operational, and technical capabilities and ethical conduct provides a screening process to ensure provider competence.

Denial, Suspension and Revocation of Registration
Procedures should be adopted to take action against gas services providers who fail to provide required information or who violate any of the Commission’s prescribed standards.

Information Disclosure
Gas services providers would be required to provide consumers with a written notice of price, terms and conditions, and a bill containing standardized information. gas services providers would also be required to file any standard service offerings with the Commission.

Third Party Verification
Independent verification of a customer’s change of provider is used as a deterrent to a practice known as “slamming,” or unauthorized change of provider, and is mandatory for the core gas aggregation program, as well as the competitive electric and telecommunications industries.

Complaint Resolution Process
Consumers unable to resolve disputes with their service providers should have access to a convenient, neutral complaint resolution forum.

Consumer Education Program
Consumers should be provided with information about the choices available to them, how to protect themselves from unscrupulous providers, and their rights and remedies under the law.

Rate Comparison-Pricing Database
Real-time pricing information supplied by gas services providers would provide consumers with an unbiased comparison of rates and other services.

(END OF APPENDIX B)
TABLE OF CONTENTS

				Title								     Page

ORDER IDENTIFYING PROMISING OPTIONS FOR FURTHER STUDY	2
I.	Summary of Promising Options	2
II.	Background	5
A.	Procedural History	5
B.	Goals	9
III.	A Review of Specific Change Options	10
A.	Improving Access to Transmission and Storage Services &Transmission, Storage and Balancing Rights Trading	10
1.	Intrastate Transmission	12
2.	Storage	19
3.	Divestiture of Transmission and Storage Assets	23
4.	Implications of the Open Season for Transmission Capacity on the Redwood Path	26
B.	Improving Balancing Practices	29
1.	PG&E’s OFOs	30
2.	SoCalGas’ Overnomination Events	34
3.	Daily Balancing and the Unbundling of Balancing Services	37
4.	Targeted OFOs	40
5.	Imbalance Rights Trading	41
C.	Appropriate Conditions for the Offering of Hub Services	44
1.	Lack of Competition and Resulting Price Discrimination for Hub Services	44
2.	Hub Services In the SoCalGas GCIM	47
D.	Changing Core Procurement Services	48
1.	Core Procurement	49
2.	Core Aggregation	59
3.	Treatment of Core Load for Operational Purposes and Balancing	61
4.	Elimination of Core/Noncore Distinction	62
5.	Core Subscription	62
E.	Improving the Flow of Information Related to Market Transactions	63
1.	What Market Participants Want to Know	65
a)	Information Needed to Prevent Anti-Competitive Behavior	65
b)	Information to Facilitate an Independent Assessment of the California Natural Gas Market	67
2.	Areas of Contention	70
a)	Real-Time information	70
b)	Details of Completed Transactions	72
3.	Electronic Bulletin Board	77
4.	Demand forecasts broken down by customer class	78
F.	Accountability for System Safety and Meter Choice	82
G.	Billing Options	83
H.	Cost and Rate Separation	84
I.	Enhancing Consumer Protections for Core Customers	85
1.	Commission Authority Over Consumer Protection Issues	88
2.	Consumer Protection Elements	90
a)	Gas Service Provider Registration	90
b)	Denial, Suspension and Revocation	103
c)	Written Notice and Contracts	107
d)	Customer Deposit	112
e)	Standard Bill Format	112
f)	Standard Service Plan Filing	115
g)	Third Party Verification	116
h)	Confidentiality of Information	117
i)	Complaint Resolution	118
j)	Consumer Education	122
k)	Rate Comparison-Pricing Database	127
3.	Conclusions Concerning Consumer Protections	130
J.	Statewide Consistency Assessment	130
IV.	Conclusion	131
Findings of Fact	133
Conclusions of Law	138
ORDER	140
TABLE OF CONTENTS	i
APPENDIX A
APPENDIX B